Northern States Power 10-K 23 Feb 23 2022 FY Annual report Financial data

Cover Page

Cover Page - USD ($)	12 Months Ended
	Dec. 31, 2022	Feb. 23, 2023	Jun. 30, 2022
Cover [Abstract]
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2022
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	2022
Document Fiscal Period Focus	FY
Amendment Flag	false
Entity Public Float			$ 0

Audit Information

Audit Information	12 Months Ended
	Dec. 31, 2022
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, 2022	Dec. 31, 2021	Dec. 31, 2020
Operating revenues
Electric, non-affiliates	$ 5,103	$ 4,593	$ 4,131
Electric, affiliates	514	501	440
Natural gas	1,022	623	493
Other	45	39	37
Total operating revenues	6,684	5,756	5,101
Operating expenses
Electric fuel and purchased power	2,416	2,042	1,626
Cost of natural gas sold and transported	741	385	263
Cost of sales — other	26	23	22
Operating and maintenance expenses	1,228	1,190	1,191
Conservation program expenses	163	144	119
Depreciation and amortization	1,014	926	825
Taxes (other than income taxes)	276	264	259
Total operating expenses	5,864	4,974	4,305
Operating income	820	782	796
Other (expense) income, net	(7)	4	2
Allowance for funds used during construction — equity	29	30	25
Interest charges and financing costs
Interest charges — includes other financing costs of $8, $8 and $8, respectively	291	271	249
Allowance for funds used during construction — debt	(12)	(13)	(11)
Total interest charges and financing costs	279	258	238
Income before income taxes	563	558	585
Income tax benefit	(112)	(48)	(6)
Net income	$ 675	$ 606	$ 591

CONSOLIDATED STATEMENTS OF IN_2

CONSOLIDATED STATEMENTS OF INCOME (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
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, 2022	Dec. 31, 2021	Dec. 31, 2020
Comprehensive income:
Net income	$ 675	$ 606	$ 591
Derivative instruments:
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax	1	2	1
Total other comprehensive income	2	2	1
Total comprehensive income	677	608	592
Net pension and retiree medical gain arising during the period, net of tax of $—	$ 1	$ 0	$ 0

CONSOLIDATED STATEMENTS OF CO_2

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Statement of Comprehensive Income [Abstract]
Reclassification adjustment from AOCI on derivatives, tax	$ 0	$ 0	$ 0

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Operating activities
Net income	$ 675	$ 606	$ 591
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	1,021	932	831
Nuclear fuel amortization	118	114	123
Deferred income taxes	(214)	(36)	(67)
Allowance for equity funds used during construction	(29)	(30)	(25)
Provision for bad debts	21	24	24
Changes in operating assets and liabilities:
Accounts receivable	(102)	(89)	(55)
Accrued unbilled revenues	(53)	(71)	1
Inventories	(85)	(22)	(14)
Other current assets	(4)	3	(9)
Accounts payable	46	69	(1)
Net regulatory assets and liabilities	443	(282)	(87)
Other current liabilities	39	(5)	(58)
Pension and other employee benefit obligations	(11)	(41)	(54)
Other, net	6	(50)	(8)
Net cash provided by operating activities	1,871	1,122	1,192
Investing activities
Capital/construction expenditures	(1,901)	(1,866)	(1,901)
Purchase of investment securities	(1,332)	(757)	(1,398)
Proceeds from the sale of investment securities	1,297	743	1,378
Investments in utility money pool arrangement	(1,522)	(821)	(718)
Repayments from utility money pool arrangement	1,613	730	718
Other, net	6	1	1
Net cash used in investing activities	(1,839)	(1,970)	(1,920)
Financing activities
Proceeds from (repayments of) short-term borrowings, net	207	(179)	149
Borrowings under utility money pool arrangement	6	434	136
Repayments under utility money pool arrangement	(6)	(434)	(136)
Proceeds from issuance of long-term debt	489	836	677
Repayment of long-term debt	(300)	0	(300)
Capital contributions from parent	124	649	527
Dividends paid to parent	(560)	(431)	(408)
Other, net	0	0	3
Net cash (used in) provided by financing activities	(40)	875	648
Net change in cash, cash equivalents and restricted cash	(8)	27	(80)
Cash, cash equivalents and restricted cash at beginning of period	73	46	126
Cash, cash equivalents and restricted cash at end of period	65	73	46
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	(268)	(245)	(230)
Cash (paid) received for income taxes, net	(100)	11	(53)
Supplemental disclosure of non-cash investing and financing transactions:
Accrued property, plant and equipment additions	208	242	74
Inventory transfers to property, plant and equipment	10	8	24
Operating lease right-of-use assets	1	4	2
Allowance for equity funds used during construction	$ 29	$ 30	$ 25

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions		Dec. 31, 2022	Dec. 31, 2021
Current assets
Cash, cash equivalents and restricted cash at end of period		$ 65	$ 73
Accounts receivable, net		534	429
Accounts receivable from affiliates		45	29
Investments in money pool arrangements		0	91
Accrued unbilled revenues		372	319
Inventories		384	309
Regulatory assets		384	527
Derivative instruments		89	53
Prepayments and other		62	46
Total current assets		1,935	1,876
Property, plant and equipment, net		17,478	16,430
Other assets
Nuclear decommissioning fund and other investments		2,930	3,308
Regulatory assets		894	718
Derivative instruments		68	33
Operating lease right-of-use assets		324	408
Other		29	36
Total other assets		4,245	4,503
Total assets		23,658	22,809
Current liabilities
Current portion of long-term debt		400	300
Short-term debt		207	0
Accounts payable		619	522
Accounts payable to affiliates		89	63
Regulatory liabilities	[1]	191	117
Taxes accrued		272	260
Accrued interest		79	78
Dividends payable to parent		122	96
Derivative instruments		42	35
Operating lease liabilities		98	90
Other		227	166
Total current liabilities		2,346	1,727
Deferred credits and other liabilities
Deferred income taxes		1,666	1,949
Deferred investment tax credits		15	17
Regulatory liabilities	[1]	1,983	1,927
Asset retirement obligations		2,727	2,585
Derivative instruments		102	71
Pension and employee benefit obligations		155	112
Operating lease liabilities		256	353
Other		30	48
Total deferred credits and other liabilities		6,934	7,062
Commitments and contingencies
Capitalization
Long-term debt		6,542	6,447
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		$ 5,374	$ 5,202
Retained earnings		2,480	2,391
Accumulated other comprehensive loss		(18)	(20)
Total common stockholder's equity		7,836	7,573
Total liabilities and equity		$ 23,658	$ 22,809
[1]Revenue subject to refund of $67 million and $15 million for 2022 and 2021, 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, 2019		1,000,000
Balance at beginning of period at Dec. 31, 2019	$ 6,081	$ 0	$ 4,068	$ 2,036	$ (23)
Increase (Decrease) in Stockholder's Equity
Net income	591			591
Other comprehensive income	1				1
Dividends declared to parent	(420)			(420)
Contribution of capital by parent	517		517
Adoption of ASC Topic 326	(1)			(1)
Balance at end of period (shares) at Dec. 31, 2020		1,000,000
Balance at end 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	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)

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2022
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, 2022 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 in recording 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 information available. 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. NSP-Minnesota uses 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. The effects of tax rate changes that are attributable to the utility subsidiaries are generally subject to a normalization method of accounting. Therefore, the revaluation of most of the utility subsidiaries’ net deferred taxes upon a tax rate reduction results in the establishment of a net regulatory liability, refundable to utility customers over the remaining life of the related assets. 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 the 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. Utility rate regulation has resulted in the recognition of regulatory assets and liabilities related to income taxes. 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 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 are charged to expense as incurred. Maintenance and replacement of items determined to be less than a unit of property are charged to operating expenses 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 4.0% for 2022, 3.7% for 2021 and 3.7% for 2020. See Note 3 for further information. AROs — NSP-Minnesota records AROs as a liability for the fair value of an ARO to be recognized in the period incurred (if it 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 3 years and submitted to the state commissions for approval. Due to other regulatory activity, the next decommissioning study has been deferred one year until 2024. NSP-Minnesota recovers regulator-approved decommissioning costs of its nuclear power plants over each facility’s expected service life, typically based on the triennial decommissioning studies. The studies consider estimated future costs of decommissioning and the market value of investments in trust funds and recommend annual funding amounts. Amounts collected in rates are deposited in the trust funds. For financial reporting purposes, NSP-Minnesota accounts for nuclear decommissioning as an ARO. Restricted funds for the payment of 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. Future costs of restoring 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 3 months or less at the time of purchase to be cash equivalents. Accounts Receivable and Allowance for Bad Debts — Accounts receivable are stated at the actual billed amount net of an allowance for bad debts. NSP-Minnesota establishes an allowance for uncollectible receivables based on a policy that reflects its expected exposure to the credit risk of customers. As of Dec. 31, 2022 and 2021, the allowance for bad debts wa s $46 million and $45 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, 2022 Dec. 31, 2021 Inventories Materials and supplies $ 200 $ 181 Fuel 103 81 Natural gas 81 47 Total inventories $ 384 $ 309 Fair Value Measurements — NSP-Minnesota presents cash equivalents, interest rate derivatives, commodity derivatives 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 the pension and postretirement plan assets and nuclear decommissioning fund, 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. Any derivative instruments 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 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 on a net basis in electric operating revenues in the consolidated statements of income.

Accounting Pronouncements

Accounting Pronouncements	12 Months Ended
	Dec. 31, 2022
Accounting Standards Update and Change in Accounting Principle [Abstract]
Accounting Pronouncements	As of Dec. 31, 2022, there was no material impact from the recent adoption of new accounting pronouncements, nor expected material impact from recently issued accounting pronouncements yet to be adopted, on NSP-Minnesota’s consolidated financial statements.

Property Plant and Equipment Pr

Property Plant and Equipment Property Plant and Equipment	12 Months Ended
	Dec. 31, 2022
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment Disclosure	Major classes of property, plant and equipment (Millions of Dollars) Dec. 31, 2022 Dec. 31, 2021 Property, plant and equipment, net Electric plant $ 20,114 $ 19,154 Natural gas plant 2,100 1,864 Common and other property 1,156 1,007 Plant to be retired (a) 646 719 CWIP 907 984 Total property, plant and equipment 24,923 23,728 Less accumulated depreciation (7,734) (7,606) Nuclear fuel 3,183 3,081 Less accumulated amortization (2,894) (2,773) Property, plant and equipment, net $ 17,478 $ 16,430 (a) Amounts include regulator-approved retirements of Sherco Units 1, 2 and 3 and A.S. King and are presented net of accumulated depreciation. Joint Ownership of Generation and Transmission Facilities Jointly owned assets as of Dec. 31, 2022: (Millions of Dollars, Except Percent Owned) Plant in Service Accumulated Depreciation Percent Owned Electric generation: Sherco Unit 3 $ 623 $ 468 59 % Sherco common facilities 180 115 80 Sherco substation 5 4 59 Electric transmission: Grand Meadow 11 3 50 Huntley Wilmarth 49 1 50 CapX2020 818 124 51 Total (a) $ 1,686 $ 715 (a) Projects additionally include $4 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, 2022
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, 2022 Dec. 31, 2021 (a) Regulatory Assets Current Noncurrent Current Noncurrent Pension and retiree medical obligations 9 Various $ 12 $ 347 $ 24 $ 301 Recoverable deferred taxes on AFUDC Plant lives — 112 — 114 Excess deferred taxes — TCJA 7 Various 10 103 10 113 Deferred natural gas and electric energy/fuel costs One five 110 65 138 190 Net AROs (b) 1, 10 Various — 62 — (316) Benson biomass PPA termination and asset purchase Six 10 45 10 55 PI extended power uprate 12 years 4 42 4 46 Contract valuation adjustments (c) 1, 8 Term of related contract 16 28 18 34 Purchased power contracts costs Term of related contract 7 19 6 27 Conservation programs (d) 1 One two 6 19 7 22 Nuclear refueling outage costs 1 One two 30 12 37 16 Losses on reacquired debt Term of related debt 1 10 1 11 Sales true-up and revenue decoupling One 53 — 33 56 Laurentian biomass PPA termination Less than one 18 — 18 18 Renewable resources and environmental initiatives One 50 — 170 3 Gas pipeline inspection and remediation costs One 42 — 33 — Other Various 15 30 18 28 Total regulatory assets $ 384 $ 894 $ 527 $ 718 (a) Prior period amounts have been restated to conform with current year presentation. (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 certain long-term PPAs used to meet energy capacity requirements and valuation adjustments on natural gas commodity purchases. (d) Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions. Components of regulatory liabilities: (Millions of Dollars) See Note(s) Remaining Amortization Period Dec. 31, 2022 Dec. 31, 2021 (a) Regulatory Liabilities Current Noncurrent Current Noncurrent Deferred income tax adjustments and TCJA refunds (b) 7 Various $ 6 $ 1,200 $ 9 $ 1,256 Plant removal costs 1, 10 Various — 693 — 613 Revenue decoupling Two years — 22 — — Renewable resources and environmental initiatives Various 6 19 1 10 ITC deferrals 1 Various — 17 — 7 Formula rates One two 6 9 4 7 Contract valuation adjustments (c) 1, 8 Less than one 56 — 29 — Conservation programs Less than one 42 — — — DOE Settlement N/A — — 14 — Deferred natural gas and electric energy/fuel costs Less than one 26 — 14 — Other Various 49 23 46 34 Total regulatory liabilities (d) $ 191 $ 1,983 $ 117 $ 1,927 (a) Prior period amounts have been restated to conform with current year presentation. (b) 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. (c) Includes the fair value of FTR instruments utilized/intended to offset the impacts of transmission system congestion. (d) Revenue subject to refund of $67 million and $15 million for 2022 and 2021, respectively, is included in other current liabilities.

Borrowings and Other Financing

Borrowings and Other Financing Instruments	12 Months Ended
	Dec. 31, 2022
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, 2022 Year Ended Dec. 31 2022 2021 2020 Borrowing limit $ 250 $ 250 $ 250 $ 250 Amount outstanding at period end — — — — Average amount outstanding — — 6 3 Maximum amount outstanding 4 4 236 116 Weighted average interest rate, computed on a daily basis 3.87 % 3.87 % 0.07 % 1.53 % 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, 2022 Year Ended Dec. 31 2022 2021 2020 Borrowing limit $ 700 $ 700 $ 500 $ 500 Amount outstanding at period end 207 207 — 179 Average amount outstanding 81 21 26 10 Maximum amount outstanding 290 290 317 179 Weighted average interest rate, computed on a daily basis 4.32 % 4.14 % 0.18 % 1.25 % Weighted average interest rate at end of period 4.64 4.64 N/A 0.18 Letters of Credit — NSP-Minnesota uses letters of credit, typically with terms of one year, to provide financial guarantees for certain operating obligations. At Dec. 31, 2022 and 2021, there were $15 million and $9 million of letters of credit outstanding under the credit facility, respectively. The contract amounts of these letters of credit approximate their fair value and are subject to fees. Credit Facility — In order to use commercial paper programs to fulfill short-term funding needs, NSP-Minnesota must have revolving credit facilities in place at least equal to the amount of their respective commercial paper borrowing limits and cannot issue commercial paper exceeding available capacity under these credit facilities. The lines of credit provide short-term financing in the form of notes payable to banks, letters of credit and back-up support for commercial paper borrowings. Features of NSP-Minnesota’s credit facility: Debt-to-Total Capitalization Ratio (a) Amount Facility May Be Increased (millions of dollars) Additional Periods for Which a One-Year Extension May Be Requested (b) 2022 2021 48 % 47 % $ 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, 2022, 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, 2022 (in millions of dollars): Credit Facility (a) Drawn (b) Available $ 700 $ 222 $ 478 (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, 2022 and 2021. 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, 2022, NSP-Minnesota had $54 million outstanding letters of credit under the $75 million Bilateral Credit Agreement. 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 2022 2021 First mortgage bonds 2.15 % Aug. 15, 2022 $ — $ 300 First mortgage bonds 2.60 May 15, 2023 400 400 First mortgage bonds 7.125 July 1, 2025 250 250 First mortgage bonds 6.50 March 1, 2028 150 150 First mortgage bonds (a) 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 (a) 3.20 April 1, 2052 425 425 First mortgage bonds (b) 4.50 June 1,2052 500 — Other long-term debt 3 3 Unamortized discount (45) (44) Unamortized debt issuance cost (66) (62) Current maturities (400) (300) Total long-term debt $ 6,542 $ 6,447 (a) 2021 financing. (b) 2022 financing. Maturities of long-term debt are as follows: (Millions of Dollars) 2023 $ 400 2024 — 2025 250 2026 — 2027 — Deferred Financing Costs — Deferred financing costs of approximately $66 million and $62 million, net of amortization, are presented as a deduction from the carrying amount of long-term debt at Dec. 31, 2022 and 2021, 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 from retained earnings. NSP-Minnesota’s state regulatory commissions additionally impose dividend limitations, which are more restrictive than those imposed by the FERC. Requirements and actuals as of Dec. 31, 2022: Equity to Total Capitalization Ratio Equity to Total Capitalization Ratio Actual Low High 2022 47.2 % 57.6 % 52.3 % Unrestricted Retained Earnings Total Capitalization Limit on Total Capitalization $ 1,446 million $ 14,984 million $ 16,140 million

Revenues

Revenues	12 Months Ended
	Dec. 31, 2022
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, 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 Year Ended Dec. 31, 2020 (Millions of Dollars) Electric Natural Gas All Other Total Major revenue types Revenue from contracts with customers: Residential $ 1,375 $ 261 $ 31 $ 1,667 C&I 1,935 189 — 2,124 Other 33 — 6 39 Total retail 3,343 450 37 3,830 Wholesale 202 — — 202 Transmission 238 — — 238 Interchange 440 — — 440 Other 15 7 — 22 Total revenue from contracts with customers 4,238 457 37 4,732 Alternative revenue and other 333 36 — 369 Total revenues $ 4,571 $ 493 $ 37 $ 5,101

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2022
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: 2022 2021 (c) 2020 (c) 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) (39.6) (27.8) (19.3) Plant regulatory differences (b) (6.7) (8.1) (7.2) Other tax credits, net NOL & tax credit allowances (1.3) (1.4) (1.2) NOL Carryback — — (2.1) Other, net (0.3) 0.7 0.8 Effective income tax rate (19.9) % (8.6) % (1.0) % (a) Wind PTCs are credited to customers (reduction to revenue) and do not materially impact net income. (b) Regulatory differences for income tax primarily relate to the credit of excess deferred taxes to customers through the average rate assumption method. Income tax benefits associated with the credit of excess deferred taxes are offset by corresponding revenue reductions. (c) Prior period amounts have been restated to conform with current year presentation. Components of income tax expense for years ended Dec. 31: (Millions of Dollars) 2022 2021 2020 Current federal tax expense (benefit) $ 70 $ (10) $ 41 Current state tax expense (benefit) 26 (1) 12 Current change in unrecognized tax expense 8 1 9 Deferred federal tax benefit (237) (87) (102) Deferred state tax expense 23 49 38 Deferred change in unrecognized tax expense (benefit) — 2 (3) Deferred ITCs (2) (2) (1) Total income tax benefit $ (112) $ (48) $ (6) Components of deferred income tax expense as of Dec. 31: (Millions of Dollars) 2022 2021 2020 Deferred tax (benefit) expense excluding items below $ (283) $ 109 61 Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities 70 (145) (127) Tax expense allocated to other comprehensive income, and other (1) — (1) Deferred tax benefit $ (214) $ (36) $ (67) Components of the net deferred tax liability as of Dec. 31: (Millions of Dollars) 2022 2021 (a) Deferred tax liabilities: Differences between book and tax bases of property $ 2,708 $ 2,679 Regulatory assets 189 214 Operating lease assets 98 123 Deferred fuel costs 49 92 Pension expense 68 73 Other 10 13 Total deferred tax liabilities $ 3,122 $ 3,194 Deferred tax assets: Tax credit carryforward $ 977 $ 782 Regulatory Liabilities 325 279 Operating lease liabilities 98 123 NOL and tax credit valuation allowances (58) (64) Other employee benefits 27 32 NOL carryforward 15 43 Deferred ITCs 5 5 Rate refund 28 11 Other 39 34 Total deferred tax assets $ 1,456 $ 1,245 Net deferred tax liability $ 1,666 $ 1,949 (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) 2022 2021 Federal NOL carryforward $ 2 $ 77 Federal tax credit carryforwards 909 704 State NOL carryforwards 184 344 Valuation allowances for state NOL carryforwards (1) (1) State tax credit carryforwards, net of federal detriment (a) 68 78 Valuation allowances for state credit carryforwards, net of federal benefit (b) (58) (64) (a) State tax credit carryforwards are net of federal detriment of $18 million and $21 million as of Dec. 31, 2022 and 2021, respectively. (b) Valuation allowances for state tax credit carryforwards were net of federal benefit of $15 million and $17 million as of Dec. 31, 2022 and 2021, respectively. Federal carryforward periods expire starting 2032 and state carryforward periods expire starting 2022. Federal Tax Loss Carryback Claims — In 2020, Xcel Energy identified certain expenses related to tax years 2009 - 2011 that qualify for an extended carryback claim. As a result, a tax benefit of approximately $13 million was recognized in 2020. 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 2024 2019 October 2023 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. Xcel Energy has recognized its best estimate of income tax expense that will result from a final resolution of this issue; however, the outcome and timing of a resolution is unknown. State Audits — NSP-Minnesota is a member of the Xcel Energy affiliated group that files consolidated state income tax returns. As of Dec. 31, 2022, 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 2024 Minnesota 2018 June 2023 In 2020, Minnesota began an audit of tax years 2015-2018. In 2022, the state of Minnesota issued its audit report without any material adjustments. Unrecognized Tax Benefits — 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, 2022 Dec. 31, 2021 Unrecognized tax benefit — Permanent tax positions $ 31 $ 23 Unrecognized tax benefit — Temporary tax positions 3 3 Total unrecognized tax benefit $ 34 $ 26 Changes in unrecognized tax benefits: (Millions of Dollars) 2022 2021 2020 Balance at Jan. 1 $ 26 $ 24 $ 20 Additions based on tax positions related to the current year 2 2 2 Reductions based on tax positions related to the current year — — — Additions for tax positions of prior years 6 — 16 Reductions for tax positions of prior years — — (14) Balance at Dec. 31 $ 34 $ 26 $ 24 Unrecognized tax benefits were reduced by tax benefits associated with NOL and tax credit carryforwards: (Millions of Dollars) Dec. 31, 2022 Dec. 31, 2021 NOL and tax credit carryforwards $ (13) $ (13) As the IRS progresses its review of the tax loss carryback claims and as state audits progress, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $22 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) 2022 2021 2020 Payable for interest related to unrecognized tax benefits at Jan. 1 $ (2) $ (2) $ (2) Interest expense related to unrecognized tax benefits (1) — — Payable for interest related to unrecognized tax benefits at Dec. 31 $ (3) $ (2) $ (2) No amounts were accrued for penalties related to unrecognized tax benefits as of Dec. 31, 2022, 2021 or 2020.

Fair Value of Financial Assets

Fair Value of Financial Assets and Liabilities	12 Months Ended
	Dec. 31, 2022
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 billion and $1.3 billion as of Dec. 31, 2022 and 2021, respectively, and unrealized losses were $90 million and $7 million as of Dec. 31, 2022 and 2021, respectively. Non-derivative instruments with recurring fair value measurements in the nuclear decommissioning fund: 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. Dec. 31, 2021 Fair Value (Millions of Dollars) Cost Level 1 Level 2 Level 3 NAV Total Nuclear decommissioning fund (a) Cash equivalents $ 64 $ 64 $ — $ — $ — $ 64 Commingled funds 856 — — — 1,294 1,294 Debt securities 631 — 666 9 — 675 Equity securities 411 1,222 1 — — 1,223 Total $ 1,962 $ 1,286 $ 667 $ 9 $ 1,294 $ 3,256 (a) Reported in nuclear decommissioning fund and other investments on the consolidated balance sheets, which also includes $52 million of rabbi trust assets and other miscellaneous investments. For the years ended Dec. 31, 2022 and 2021, 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, 2022: 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 $ 6 $ 204 $ 250 $ 216 $ 676 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 $13 million at Dec. 31, 2022 and 2021, 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, 2022, 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, 2022, NSP-Minnesota had no 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, 2022 and 2021 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, 2022, 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, 2022 Dec. 31, 2021 MWh of electricity 44 57 MMBtu of natural gas 88 85 (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, 2022, six of NSP-Minnesota’s ten most significant counterparties for these activities, comprising $38 million or 34% 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 $28 million or 25% 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. One of these significant counterparties, comprising $47 million or 41% of this credit exposure, had credit quality less than investment grade, based on internal analysis. Four 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, 2022 and 2021, there were $4 million and $3 million, respectively, of derivative liabilities with such underlying contract provisions, respectively. Certain contracts also contain cross default provisions that may require the posting of collateral or settlement of the contracts if there was a failure under other financing arrangements related to payment terms or other covenants. As of Dec. 31, 2022 and 2021, there were approximately $76 million and $48 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, 2022 and 2021. Recurring Derivative Fair Value Measurements Impact of derivative activity: Pre-Tax Fair Value (Millions of Dollars) Accumulated Other Comprehensive Loss Regulatory (Assets) and Liabilities 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 $ — $ — Year Ended Dec. 31, 2020 Other derivative instruments Electric commodity $ — $ 2 Natural gas commodity — (2) 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, 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 Year Ended Dec. 31, 2020 Derivatives designated as cash flow hedges Interest rate $ 1 (a) $ — $ — Total $ 1 $ — $ — Other derivative instruments Commodity trading $ — $ — $ (5) (b) Electric commodity $ — $ (3) (c) $ — Natural gas commodity — 2 (d) (4) (d)(e) Total $ — $ (1) $ (9) (a) Recorded to interest charges. (b) Recorded to electric revenues. Presented amounts do not reflect non-derivative transactions or margin sharing with customers. (c) Recorded to electric fuel and purchased power. These derivative settlement gains and losses are shared with electric customers through fuel and purchased energy cost-recovery mechanisms and reclassified out of income as regulatory assets or liabilities, as appropriate. FTR settlements are shared with customers and do not have a material impact on net income. Presented amounts reflect changes in fair value between 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, 2022, 2021 and 2020. Derivative assets and liabilities measured at fair value on a recurring basis were as follows: Dec. 31, 2022 Dec. 31, 2021 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 $ 15 $ 38 $ 33 $ 86 $ (58) $ 28 $ 9 $ 40 $ 22 $ 71 $ (53) $ 18 Electric commodity — — 58 58 (2) 56 — — 30 30 (1) 29 Natural gas commodity — 5 — 5 — 5 — 6 — 6 — 6 Total current derivative assets $ 15 $ 43 $ 91 $ 149 $ (60) $ 89 $ 9 $ 46 $ 52 $ 107 $ (54) $ 53 Noncurrent derivative assets Other derivative instruments: Commodity trading $ 21 $ 40 $ 66 $ 127 $ (59) $ 68 $ 6 $ 34 $ 35 $ 75 $ (42) $ 33 Total noncurrent derivative assets $ 21 $ 40 $ 66 $ 127 $ (59) $ 68 $ 6 $ 34 $ 35 $ 75 $ (42) $ 33 Dec. 31, 2022 Dec. 31, 2021 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 Other derivative instruments: Commodity trading $ 23 $ 60 $ 6 $ 89 $ (63) $ 26 $ 13 $ 58 $ 4 $ 75 $ (58) $ 17 Electric commodity — — 2 2 (2) — — — 1 1 (1) — Natural gas commodity — 2 — 2 — 2 — 4 — 4 — 4 Total current derivative liabilities $ 23 $ 62 $ 8 $ 93 $ (65) 28 $ 13 $ 62 $ 5 $ 80 $ (59) 21 PPAs (b) 14 14 Current derivative instruments $ 42 $ 35 Noncurrent derivative liabilities Other derivative instruments: Commodity trading $ 37 $ 55 $ 42 $ 134 $ (60) $ 74 $ 15 $ 48 $ 26 $ 89 $ (53) $ 36 Total noncurrent derivative liabilities $ 37 $ 55 $ 42 $ 134 $ (60) 74 $ 15 $ 48 $ 26 $ 89 $ (53) 36 PPAs (b) 28 35 Noncurrent derivative instruments $ 102 $ 71 (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, 2022 and 2021, derivative assets and liabilities include no obligations to return cash collateral. At Dec. 31, 2022 and 2021, derivative assets and liabilities include rights to reclaim cash collateral of $6 million and $16 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) 2022 2021 2020 Balance at Jan. 1 $ 56 $ (11) $ 5 Purchases (a) 157 54 28 Settlements (a) (195) (82) (49) Net transactions recorded during the period: Gains (losses) recognized in earnings (b) 91 72 (8) Net gains (losses) recognized as regulatory assets and liabilities (a) (2) 23 13 Balance at Dec. 31 $ 107 $ 56 $ (11) (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: 2022 2021 (Millions of Dollars) Carrying Amount Fair Value Carrying Amount Fair Value Long-term debt, including current portion $ 6,942 $ 5,995 $ 6,747 $ 7,761 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, 2022 and 2021, 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, 2021
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 4.86, 1.96 and 1.78% in 2022, 2021, and 2020, 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, 2022 and 2021 were $11 million and $43 million, respectively, of which $2 million and $3 million was attributable to NSP-Minnesota in 2022 and 2021, respectively. Xcel Energy recognized net benefit cost for the SERP and nonqualified plans of $17 million in 2022 and $4 million in 2021, respectively, of which immaterial amounts were attributable to NSPM. 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 2022 were below the assumed level of 6.60%. • Investment returns in 2021 were above the assumed level of 6.60%. • Investment returns in 2020 were above the assumed level of 7.10%. • In 2023, 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, 2022 (a) Dec. 31, 2021 (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 $ 26 $ — $ — $ — $ 26 $ 31 $ — $ — $ — $ 31 Commingled funds 201 — — 201 402 304 — — 274 578 Debt securities — 129 1 — 130 — 219 1 — 220 Equity securities 11 — — — 11 16 — — — 16 Other — 1 — — 1 — 1 — 7 8 Total $ 238 $ 130 $ 1 $ 201 $ 570 $ 351 $ 220 $ 1 $ 281 $ 853 (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, 2022 (a) Dec. 31, 2021 (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 $ 2 $ — $ — $ — $ 1 $ 1 Debt securities — 2 — — 2 — 2 — — 2 Total $ 1 $ 3 $ — $ 1 $ 5 $ — $ 2 $ — $ 1 $ 3 (a) See Note 8 for further information on fair value measurement inputs and methods. No assets were transferred in or out of Level 3 for 2022 or 2021. Funded Status — Benefit obligations for both pension and postretirement plans decreased from Dec. 31, 2021 to Dec. 31, 2022, due primarily to benefit payments and increases in discount rates used in actuarial valuations. 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) 2022 2021 2022 2021 Change in Benefit Obligation: Obligation at Jan. 1 $ 877 $ 989 $ 64 $ 73 Service cost 27 30 — — Interest cost 25 25 2 2 Plan amendments 1 1 — — Actuarial gain (139) (28) (13) (5) Benefit payments (134) (140) (5) (6) Obligation at Dec. 31 $ 657 $ 877 $ 48 $ 64 Change in Fair Value of Plan Assets: Fair value of plan assets at Jan. 1 $ 853 $ 897 $ 3 $ 2 Actual return on plan assets (154) 62 — — Employer contributions 5 34 7 7 Benefit payments (134) (140) (5) (6) Fair value of plan assets at Dec. 31 $ 570 $ 853 $ 5 $ 3 Funded status of plans at Dec. 31 $ (87) $ (24) $ (43) $ (61) Amounts recognized in the Consolidated Balance Sheet at Dec. 31: Current liabilities $ — $ — $ (1) $ (3) Noncurrent liabilities (87) (24) (42) (58) Net amounts recognized $ (87) $ (24) $ (43) $ (61) Pension Benefits Postretirement Benefits Significant Assumptions Used to Measure Benefit Obligations: 2022 2021 2022 2021 Discount rate for year-end valuation 5.80 % 3.08 % 5.80 % 3.09 % Expected average long-term increase in compensation level 4.25 3.75 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 % 5.30 % Health care costs trend rate — initial: Post-65 N/A N/A 5.50 % 4.90 % 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 7 4 Accumulated benefit obligation for the pension plan was $600 million and $811 million as of Dec. 31, 2022 and 2021, 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) 2022 2021 2020 2022 2021 2020 Service cost $ 27 $ 30 $ 27 $ — $ — $ — Interest cost 25 25 31 2 2 2 Expected return on plan assets (48) (52) (55) — — — Amortization of prior service cost — — — (3) (3) (3) Amortization of net loss 24 34 33 1 2 1 Settlement charge (a) 38 35 — — — — Net periodic pension cost 66 72 36 — 1 — Effects of regulation (32) (44) (4) — — — Net benefit cost recognized for financial reporting $ 34 $ 28 $ 32 $ — $ 1 $ — Significant Assumptions Used to Measure Costs: Discount rate 3.08 % 2.71 % 3.49 % 3.09 % 2.65 % 3.47 % Expected average long-term increase in compensation level 3.75 3.75 3.75 — — — Expected average long-term rate of return on assets 6.60 6.60 7.10 4.10 4.10 4.50 (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 2020. Pension Benefits Postretirement Benefits (Millions of Dollars) 2022 2021 2022 2021 Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost: Net loss $ 309 $ 307 $ 16 $ 31 Prior service credit — — (1) (4) Total $ 309 $ 307 $ 15 $ 27 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 $ 12 $ 25 $ — $ — Noncurrent regulatory assets 297 282 14 25 Deferred income taxes — — — 1 Net-of-tax accumulated other comprehensive income — — 1 1 Total $ 309 $ 307 $ 15 $ 27 Measurement date Dec 31, 2022 Dec 31, 2021 Dec 31, 2022 Dec 31, 2021 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 2020 - 2023 to meet minimum funding requirements. Total voluntary and required pension funding contributions across all four of Xcel Energy’s pension plans were as follows: • $50 million in January 2023, of which $23 million is 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. • $150 million in 2020, of which $44 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: • $12 million expected in 2023, of which $6 million is 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. • $11 million during 2020, of which $6 million was attributable to NSP-Minnesota. Targeted asset allocations: Pension Benefits Postretirement Benefits 2022 2021 2022 2021 Domestic and international equity securities 33 % 33 % 16 % 15 % Long-duration fixed income and interest rate swap securities 38 37 — — Short-to-intermediate fixed income securities 9 11 71 71 Alternative investments 18 17 12 8 Cash 2 2 1 6 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 2022 and 2020, there were no significant plan amendments made 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 Gross Projected Postretirement Health Care Benefit Payments (a) 2023 $ 84 $ 6 2024 64 5 2025 64 5 2026 61 5 2027 59 4 2028-2032 279 17 (a) Amount is reported net of expected Medicare Part D subsidies, which are immaterial. 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 $13 million in 2022 and $12 million in 2021 and 2020. 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 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, 2022
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 Southern Minnesota Municipal Power Agency (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 for repair. NSP-Minnesota notified the MPUC of its proposal to refund settlement proceeds to customers through the fuel clause adjustment. 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 March 2020, NSP-Minnesota’s insurers filed a petition seeking additional review by the Minnesota Supreme Court. In April 2020, the Minnesota Supreme Court denied the insurers’ petition for further review, ending the litigation. In January 2021, the Minnesota Office of the Attorney General and DOC recommended that NSP-Minnesota refund approximately $17 million of replacement power costs previously recovered through the fuel clause adjustment. NSP-Minnesota subsequently filed its response, asserting 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. 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 (including Opinion Nos. 569, 569A and 569B) 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. Historical MGP, Landfill and Disposal Sites NSP-Minnesota is investigating, remediating or performing post-closure actions at five MGP, landfill or other disposal sites across its service territories. NSP-Minnesota has recognized its best estimate 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 CCR landfills and surface impoundments. Currently, NSP-Minnesota has three regulated ash units in operation. 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 $40 million may be required for NSP-Minnesota to comply with the requirements pending approval of mitigation plans from the Minnesota Pollution Control Agency. NSP-Minnesota anticipates these costs will be recoverable through regulatory mechanisms. 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 $2.9 billion and $3.3 billion at Dec. 31, 2022 and 2021, respectively. NSP-Minnesota’s AROs were as follows: 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 Common 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. 2021 (Millions Jan. 1, 2021 Amounts Incurred (a) Accretion Cash Flow Revisions (b) Dec. 31, 2021 Electric Nuclear $ 1,957 $ — $ 99 $ — $ 2,056 Wind 270 101 13 — 384 Steam and other production 67 6 2 (2) 73 Distribution 16 — — — 16 Miscellaneous — — — — — Natural gas Transmission and distribution 39 — 2 14 55 Common Miscellaneous 1 — — — 1 Total liability $ 2,350 $ 107 $ 116 $ 12 $ 2,585 (a) Amounts incurred relate to the wind farms placed in service in 2021 (Blazing Star 2, Mower and Freeborn) and removal of a utility scale battery asset. (b) In 2021, AROs were revised for changes in timing and estimates of cash flows. 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, 2022. 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 $13.7 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 $13.2 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 $138 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 $20 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 $350 million, 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 $12 million for business interruption insurance and $32 million for property damage insurance if losses exceed accumulated reserve funds. Nuclear Fuel Disposal — NSP-Minnesota is responsible for temporarily storing spent nuclear fuel from its nuclear plants. The DOE is responsible for permanently storing spent fuel from U.S. nuclear plants, but no such facility is yet available. NSP-Minnesota owns temporary on-site storage facilities for spent fuel at its Monticello and PI nuclear plants, which consist of storage pools and dry cask facilities. The Monticello dry-cask storage facility currently stores all 30 of the authorized canisters. The PI dry-cask storage facility currently stores 50 of the 64 authorized casks. Monticello’s future spent fuel will continue to be placed in its spent fuel pool. The decommissioning plan addresses the disposition of spent fuel at the end of the licensed life. A CON for additional storage at the Monticello site has been filed with the MPUC, to support possible life extension to 2040. NSP-Minnesota expects a decision by year-end 2023. Regulatory Plant Decommissioning Recovery — Decommissioning activities for NSP-Minnesota’s nuclear facilities are planned to begin at the end of each unit’s authorized retirement dates, which can be different than the currently approved NRC operating licenses. These decommissioning activities are planned to be completed at both facilities by 2101. NSP-Minnesota’s current operating licenses allow continued use of its Monticello nuclear plant until 2030 and its PI nuclear plant until 2033 for Unit 1 and 2034 for Unit 2. The MPUC reaffirmed a 60-year DECON scenario, where Monticello continues operations under a 10-year license extension (approved in April 2022). NRC approval of the extension is pending. Future decommissioning costs of nuclear facilities are estimated through triennial periodic studies that assess the costs and timing of planned nuclear decommissioning activities for each unit. The 2020 nuclear decommissioning filing was approved by the MPUC and became effective in 2022. Obligations for decommissioning are expected to be funded 100% by the external decommissioning trust fund. NSP-Minnesota had $2.9 billion and $3.3 billion of assets held in external decommissioning trusts at Dec. 31, 2022, and 2021, respectively. See Note 10 to the consolidated financial statements for additional discussion. 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 3.8%). 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 minimum 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, 2022 Dec. 31, 2021 PPAs $ 556 $ 556 Other 78 74 Gross operating lease ROU assets 634 630 Accumulated amortization (310) (222) Net operating lease ROU assets $ 324 $ 408 Components of lease expense: (Millions of Dollars) 2022 2021 2020 Operating leases PPA capacity payments $ 98 $ 96 $ 89 Other operating leases (a) 9 8 8 Total operating lease expense (b) $ 107 $ 104 $ 97 (a) Includes short-term lease expense o f $3 million, $2 million and $2 million for 2022, 2021 and 2020, 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, 2022: (Millions of Dollars) PPA (a) (b) Operating Leases Other Operating Leases Total Leases 2023 $ 98 $ 12 $ 110 2024 100 7 107 2025 79 8 87 2026 40 7 47 2027 — 7 7 Thereafter — 24 24 Total minimum obligation 317 65 382 Interest component of obligation (19) (9) (28) Present value of minimum obligation $ 298 $ 56 354 Less current portion (98) Noncurrent operating lease liabilities $ 256 Weighted-average remaining lease term in years 7.6 (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 2026. 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 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 $182 million, $149 million and $112 million in 2022, 2021 and 2020, respectively. Included in electric fuel and purchased power expenses for PPAs accounted for as executory contracts were payments for capacity of $60 million, $55 million and $52 million in 2022, 2021 and 2020, 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, 2022, 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) 2023 $ 61 $ 50 2024 63 45 2025 26 51 2026 9 48 2027 7 55 Thereafter 3 28 Total (b) $ 169 $ 277 (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 2023 and 2037. NSP-Minnesota is required to pay additional amounts depending on actual quantities shipped under these agreements. Estimated minimum purchases for these contracts as of Dec. 31, 2022: (Millions of Dollars) Coal Nuclear fuel Natural gas Natural gas 2023 $ 227 $ 144 $ 130 $ 158 2024 110 112 1 148 2025 17 158 1 138 2026 1 37 — 143 2027 1 155 — 98 Thereafter — 194 — 116 Total (a) $ 356 $ 800 $ 132 $ 801 (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. 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 it does not have the power to direct the activities that most significantly impact the entities’ economic performance. NSP-Minnesota had approximately 1,322 MW and 1,347 MW of capacity under long-term PPAs at Dec. 31, 2022 and 2021, 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, 2022
Stockholders' Equity Note [Abstract]
Other Comprehensive Income	Changes in accumulated other comprehensive loss, net of tax, for the years ended Dec. 31: 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) Other comprehensive loss before reclassifications, net of taxes of $— $ — $ 1 $ 1 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) 2021 (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 $ (19) $ (3) $ (22) Losses reclassified from net accumulated other comprehensive loss: Amortization of interest rate hedges 2 (a) — 2 Net current period other comprehensive income 2 — 2 Accumulated other comprehensive loss at Dec. 31 $ (17) $ (3) $ (20) (a) Included in interest charges.

Segments and Related Informatio

Segments and Related Information	12 Months Ended
	Dec. 31, 2022
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, transmits and distributes 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 transports, stores and distributes 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) 2022 2021 2020 Regulated Electric Operating revenues — external (a) $ 5,617 $ 5,094 $ 4,571 Intersegment revenue 1 1 1 Total revenues $ 5,618 $ 5,095 $ 4,572 Depreciation and amortization 953 869 773 Interest charges and financing costs 257 240 221 Income tax (benefit) expense (127) (53) (14) Net income 626 566 553 Regulated Natural Gas Operating revenues — external (b) $ 1,022 $ 623 $ 493 Intersegment revenue 2 1 — Total revenues $ 1,024 $ 624 $ 493 Depreciation and amortization 60 56 51 Interest charges and financing costs 22 18 17 Income tax expense 14 6 7 Net income 45 29 30 All Other Total revenues $ 45 $ 39 $ 37 Depreciation and amortization 1 1 1 Income tax (benefit) expense 1 (1) 1 Net income 4 11 8 Consolidated Total Total revenues (a)(b) $ 6,687 $ 5,758 $ 5,102 Reconciling eliminations (3) (2) (1) Total operating revenues $ 6,684 $ 5,756 $ 5,101 Depreciation and amortization 1,014 926 825 Interest charges and financing costs 279 258 238 Income tax (benefit) expense (112) (48) (6) Net income 675 606 591 (a) Operating revenues include $514 million, $501 million and $440 million of affiliate electric revenue for the years ended Dec. 31, 2022, 2021 and 2020, respectively. See Note 13 for further information.

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2022
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) 2022 2021 2020 Operating revenues: Electric $ 514 $ 501 $ 440 Gas — 1 1 Operating expenses: Purchased power 70 67 59 Transmission expense 132 121 109 Other operating expenses — paid to Xcel Energy Services Inc. 673 615 584 Interest income 1 — — Interest expense 1 — — Accounts receivable and payable with affiliates at Dec. 31: 2022 2021 (Millions of Dollars) Accounts Receivable Accounts Payable Accounts Receivable Accounts Payable NSP-Wisconsin $ 4 $ — $ 13 $ — PSCo — 2 16 — SPS — 3 — 2 Other subsidiaries of Xcel Energy Inc. 41 84 — 61 $ 45 $ 89 $ 29 $ 63

Schedule II, Valuation and Qual

Schedule II, Valuation and Qualifying Accounts	12 Months Ended
	Dec. 31, 2022
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) 2022 2021 2020 Balance at Jan. 1 $ 45 $ 33 $ 23 Additions charged to costs and expenses 21 24 24 Additions charged to other accounts (a) 6 5 5 Deductions from reserves (b) (26) (17) (19) Balance at Dec. 31 $ 46 $ 45 $ 33 (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, 2022
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.
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, 2022 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 in recording 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 information available. 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. NSP-Minnesota uses 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. The effects of tax rate changes that are attributable to the utility subsidiaries are generally subject to a normalization method of accounting. Therefore, the revaluation of most of the utility subsidiaries’ net deferred taxes upon a tax rate reduction results in the establishment of a net regulatory liability, refundable to utility customers over the remaining life of the related assets. 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 the 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. Utility rate regulation has resulted in the recognition of regulatory assets and liabilities related to income taxes. 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 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 are charged to expense as incurred. Maintenance and replacement of items determined to be less than a unit of property are charged to operating expenses 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 4.0% for 2022, 3.7% for 2021 and 3.7% for 2020. See Note 3 for further information.
Asset Retirement Obligations	AROs — NSP-Minnesota records AROs as a liability for the fair value of an ARO to be recognized in the period incurred (if it 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 3 years and submitted to the state commissions for approval. Due to other regulatory activity, the next decommissioning study has been deferred one year until 2024. NSP-Minnesota recovers regulator-approved decommissioning costs of its nuclear power plants over each facility’s expected service life, typically based on the triennial decommissioning studies. The studies consider estimated future costs of decommissioning and the market value of investments in trust funds and recommend annual funding amounts. Amounts collected in rates are deposited in the trust funds. For financial reporting purposes, NSP-Minnesota accounts for nuclear decommissioning as an ARO. Restricted funds for the payment of 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. Future costs of restoring 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 3 months or less at the time of purchase to be cash equivalents.
Accounts Receivable and Allowance for Bad Debts	Accounts Receivable and Allowance for Bad Debts — Accounts receivable are stated at the actual billed amount net of an allowance for bad debts. NSP-Minnesota establishes an allowance for uncollectible receivables based on a policy that reflects its expected exposure to the credit risk of customers. As of Dec. 31, 2022 and 2021, the allowance for bad debts wa s $46 million
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, 2022 Dec. 31, 2021 Inventories Materials and supplies $ 200 $ 181 Fuel 103 81 Natural gas 81 47 Total inventories $ 384 $ 309
Fair Value Measurements	Fair Value Measurements — NSP-Minnesota presents cash equivalents, interest rate derivatives, commodity derivatives 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 the pension and postretirement plan assets and nuclear decommissioning fund, 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. Any derivative instruments 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 — AFUDC represents the cost of capital used to finance utility construction activity and is computed by applying a composite financing rate to qualified CWIP. The amount of AFUDC capitalized as a utility construction cost is credited to other nonoperating income (for equity capital) and interest charges (for debt capital). AFUDC amounts capitalized are included in NSP-Minnesota’s rate base.
Alternative Revenue Programs	Alternative Revenue — Certain rate rider mechanisms (including decoupling/sales true up and CIP/DSM programs) qualify as alternative revenue programs. These mechanisms arise from instances in which the regulator authorizes a future surcharge in response to past activities or completed events. When certain criteria are met, including expected collection within 24 months, revenue is recognized, which may include incentives and return on rate base items. Billing amounts are revised periodically for differences between total amount collected and revenue earned, which may increase or decrease the level of revenue collected from customers. Alternative revenues arising from these programs are presented on a gross basis and disclosed separately from revenue from contracts with customers. See Note 6 for further information. Conservation Programs — Costs incurred for 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 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, 2022
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, 2022 Dec. 31, 2021 Inventories Materials and supplies $ 200 $ 181 Fuel 103 81 Natural gas 81 47 Total inventories $ 384 $ 309

Property Plant and Equipment (T

Property Plant and Equipment (Tables)	12 Months Ended
	Dec. 31, 2022
Property, Plant and Equipment [Abstract]
Public Utility Property, Plant, and Equipment	Major classes of property, plant and equipment (Millions of Dollars) Dec. 31, 2022 Dec. 31, 2021 Property, plant and equipment, net Electric plant $ 20,114 $ 19,154 Natural gas plant 2,100 1,864 Common and other property 1,156 1,007 Plant to be retired (a) 646 719 CWIP 907 984 Total property, plant and equipment 24,923 23,728 Less accumulated depreciation (7,734) (7,606) Nuclear fuel 3,183 3,081 Less accumulated amortization (2,894) (2,773) Property, plant and equipment, net $ 17,478 $ 16,430
Schedule of Jointly Owned Utility Plants	Joint Ownership of Generation and Transmission Facilities Jointly owned assets as of Dec. 31, 2022: (Millions of Dollars, Except Percent Owned) Plant in Service Accumulated Depreciation Percent Owned Electric generation: Sherco Unit 3 $ 623 $ 468 59 % Sherco common facilities 180 115 80 Sherco substation 5 4 59 Electric transmission: Grand Meadow 11 3 50 Huntley Wilmarth 49 1 50 CapX2020 818 124 51 Total (a) $ 1,686 $ 715 (a) Projects additionally include $4 million in CWIP.

Regulatory Assets and Liabili_2

Regulatory Assets and Liabilities (Tables)	12 Months Ended
	Dec. 31, 2022
Regulatory Assets and Liabilities Disclosure [Abstract]
Regulatory Assets	Components of regulatory assets: (Millions of Dollars) See Note(s) Remaining Amortization Period Dec. 31, 2022 Dec. 31, 2021 (a) Regulatory Assets Current Noncurrent Current Noncurrent Pension and retiree medical obligations 9 Various $ 12 $ 347 $ 24 $ 301 Recoverable deferred taxes on AFUDC Plant lives — 112 — 114 Excess deferred taxes — TCJA 7 Various 10 103 10 113 Deferred natural gas and electric energy/fuel costs One five 110 65 138 190 Net AROs (b) 1, 10 Various — 62 — (316) Benson biomass PPA termination and asset purchase Six 10 45 10 55 PI extended power uprate 12 years 4 42 4 46 Contract valuation adjustments (c) 1, 8 Term of related contract 16 28 18 34 Purchased power contracts costs Term of related contract 7 19 6 27 Conservation programs (d) 1 One two 6 19 7 22 Nuclear refueling outage costs 1 One two 30 12 37 16 Losses on reacquired debt Term of related debt 1 10 1 11 Sales true-up and revenue decoupling One 53 — 33 56 Laurentian biomass PPA termination Less than one 18 — 18 18 Renewable resources and environmental initiatives One 50 — 170 3 Gas pipeline inspection and remediation costs One 42 — 33 — Other Various 15 30 18 28 Total regulatory assets $ 384 $ 894 $ 527 $ 718 (a) Prior period amounts have been restated to conform with current year presentation. (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 certain long-term PPAs used to meet energy capacity requirements and valuation adjustments on natural gas commodity purchases. (d) Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions.
Regulatory Liabilities	Components of regulatory liabilities: (Millions of Dollars) See Note(s) Remaining Amortization Period Dec. 31, 2022 Dec. 31, 2021 (a) Regulatory Liabilities Current Noncurrent Current Noncurrent Deferred income tax adjustments and TCJA refunds (b) 7 Various $ 6 $ 1,200 $ 9 $ 1,256 Plant removal costs 1, 10 Various — 693 — 613 Revenue decoupling Two years — 22 — — Renewable resources and environmental initiatives Various 6 19 1 10 ITC deferrals 1 Various — 17 — 7 Formula rates One two 6 9 4 7 Contract valuation adjustments (c) 1, 8 Less than one 56 — 29 — Conservation programs Less than one 42 — — — DOE Settlement N/A — — 14 — Deferred natural gas and electric energy/fuel costs Less than one 26 — 14 — Other Various 49 23 46 34 Total regulatory liabilities (d) $ 191 $ 1,983 $ 117 $ 1,927 (a) Prior period amounts have been restated to conform with current year presentation. (b) 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. (c) Includes the fair value of FTR instruments utilized/intended to offset the impacts of transmission system congestion. (d) Revenue subject to refund of $67 million and $15 million for 2022 and 2021, respectively, is included in other current liabilities.

Borrowings and Other Financin_2

Borrowings and Other Financing Instruments (Tables)	12 Months Ended
	Dec. 31, 2022
Debt Disclosure [Abstract]
Money Pool [Table Text Block]	Money pool borrowings: (Millions of Dollars, Except Interest Rates) Three Months Ended Dec. 31, 2022 Year Ended Dec. 31 2022 2021 2020 Borrowing limit $ 250 $ 250 $ 250 $ 250 Amount outstanding at period end — — — — Average amount outstanding — — 6 3 Maximum amount outstanding 4 4 236 116 Weighted average interest rate, computed on a daily basis 3.87 % 3.87 % 0.07 % 1.53 % 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, 2022 Year Ended Dec. 31 2022 2021 2020 Borrowing limit $ 700 $ 700 $ 500 $ 500 Amount outstanding at period end 207 207 — 179 Average amount outstanding 81 21 26 10 Maximum amount outstanding 290 290 317 179 Weighted average interest rate, computed on a daily basis 4.32 % 4.14 % 0.18 % 1.25 % Weighted average interest rate at end of period 4.64 4.64 N/A 0.18
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) 2022 2021 48 % 47 % $ 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%.	[1],[2]
Credit Facilities	NSP-Minnesota had the following committed credit facility available as of Dec. 31, 2022 (in millions of dollars): Credit Facility (a) Drawn (b) Available $ 700 $ 222 $ 478 (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 2022 2021 First mortgage bonds 2.15 % Aug. 15, 2022 $ — $ 300 First mortgage bonds 2.60 May 15, 2023 400 400 First mortgage bonds 7.125 July 1, 2025 250 250 First mortgage bonds 6.50 March 1, 2028 150 150 First mortgage bonds (a) 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 (a) 3.20 April 1, 2052 425 425 First mortgage bonds (b) 4.50 June 1,2052 500 — Other long-term debt 3 3 Unamortized discount (45) (44) Unamortized debt issuance cost (66) (62) Current maturities (400) (300) Total long-term debt $ 6,542 $ 6,447 (a) 2021 financing.	[4],[5]
Schedule of Maturities of Long-term Debt	Maturities of long-term debt are as follows: (Millions of Dollars) 2023 $ 400 2024 — 2025 250 2026 — 2027 —
Dividend Payment Restrictions	Requirements and actuals as of Dec. 31, 2022: Equity to Total Capitalization Ratio Equity to Total Capitalization Ratio Actual Low High 2022 47.2 % 57.6 % 52.3 % Unrestricted Retained Earnings Total Capitalization Limit on Total Capitalization $ 1,446 million $ 14,984 million $ 16,140 million
[1]All extension requests are subject to majority bank group approval.[2]The credit facility has a financial covenant requiring that the debt-to-total capitalization ratio be less than or equal to 65%.[3]Includes outstanding commercial paper and letters of credit.[4]2021 financing.[5]2022 financing.

Revenues Revenues (Tables)

Revenues Revenues (Tables)	12 Months Ended
	Dec. 31, 2022
Revenue from Contract with Customer [Abstract]
Disaggregation of Revenue	NSP-Minnesota’s operating revenues consisted of the following: 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 Year Ended Dec. 31, 2020 (Millions of Dollars) Electric Natural Gas All Other Total Major revenue types Revenue from contracts with customers: Residential $ 1,375 $ 261 $ 31 $ 1,667 C&I 1,935 189 — 2,124 Other 33 — 6 39 Total retail 3,343 450 37 3,830 Wholesale 202 — — 202 Transmission 238 — — 238 Interchange 440 — — 440 Other 15 7 — 22 Total revenue from contracts with customers 4,238 457 37 4,732 Alternative revenue and other 333 36 — 369 Total revenues $ 4,571 $ 493 $ 37 $ 5,101

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2022
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 2024 2019 October 2023
Reconciliation of Unrecognized Tax Benefits	Unrecognized tax benefits - permanent vs temporary: (Millions of Dollars) Dec. 31, 2022 Dec. 31, 2021 Unrecognized tax benefit — Permanent tax positions $ 31 $ 23 Unrecognized tax benefit — Temporary tax positions 3 3 Total unrecognized tax benefit $ 34 $ 26 Changes in unrecognized tax benefits: (Millions of Dollars) 2022 2021 2020 Balance at Jan. 1 $ 26 $ 24 $ 20 Additions based on tax positions related to the current year 2 2 2 Reductions based on tax positions related to the current year — — — Additions for tax positions of prior years 6 — 16 Reductions for tax positions of prior years — — (14) Balance at Dec. 31 $ 34 $ 26 $ 24
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, 2022 Dec. 31, 2021 NOL and tax credit carryforwards $ (13) $ (13)
Interest Payable related to Unrecognized Tax Benefits	Interest payable related to unrecognized tax benefits: (Millions of Dollars) 2022 2021 2020 Payable for interest related to unrecognized tax benefits at Jan. 1 $ (2) $ (2) $ (2) Interest expense related to unrecognized tax benefits (1) — — Payable for interest related to unrecognized tax benefits at Dec. 31 $ (3) $ (2) $ (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) 2022 2021 Federal NOL carryforward $ 2 $ 77 Federal tax credit carryforwards 909 704 State NOL carryforwards 184 344 Valuation allowances for state NOL carryforwards (1) (1) State tax credit carryforwards, net of federal detriment (a) 68 78 Valuation allowances for state credit carryforwards, net of federal benefit (b) (58) (64) (a) State tax credit carryforwards are net of federal detriment of $18 million and $21 million as of Dec. 31, 2022 and 2021, respectively. (b) Valuation allowances for state tax credit carryforwards were net of federal benefit of $15 million and $17 million as of Dec. 31, 2022 and 2021, 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: 2022 2021 (c) 2020 (c) 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) (39.6) (27.8) (19.3) Plant regulatory differences (b) (6.7) (8.1) (7.2) Other tax credits, net NOL & tax credit allowances (1.3) (1.4) (1.2) NOL Carryback — — (2.1) Other, net (0.3) 0.7 0.8 Effective income tax rate (19.9) % (8.6) % (1.0) % (a) Wind PTCs are credited to customers (reduction to revenue) and do not materially impact net income. (b) Regulatory differences for income tax primarily relate to the credit of excess deferred taxes to customers through the average rate assumption method. Income tax benefits associated with the credit of excess deferred taxes 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) 2022 2021 2020 Current federal tax expense (benefit) $ 70 $ (10) $ 41 Current state tax expense (benefit) 26 (1) 12 Current change in unrecognized tax expense 8 1 9 Deferred federal tax benefit (237) (87) (102) Deferred state tax expense 23 49 38 Deferred change in unrecognized tax expense (benefit) — 2 (3) Deferred ITCs (2) (2) (1) Total income tax benefit $ (112) $ (48) $ (6) Components of deferred income tax expense as of Dec. 31: (Millions of Dollars) 2022 2021 2020 Deferred tax (benefit) expense excluding items below $ (283) $ 109 61 Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities 70 (145) (127) Tax expense allocated to other comprehensive income, and other (1) — (1) Deferred tax benefit $ (214) $ (36) $ (67)
Schedule of Deferred Tax Assets and Liabilities	Components of the net deferred tax liability as of Dec. 31: (Millions of Dollars) 2022 2021 (a) Deferred tax liabilities: Differences between book and tax bases of property $ 2,708 $ 2,679 Regulatory assets 189 214 Operating lease assets 98 123 Deferred fuel costs 49 92 Pension expense 68 73 Other 10 13 Total deferred tax liabilities $ 3,122 $ 3,194 Deferred tax assets: Tax credit carryforward $ 977 $ 782 Regulatory Liabilities 325 279 Operating lease liabilities 98 123 NOL and tax credit valuation allowances (58) (64) Other employee benefits 27 32 NOL carryforward 15 43 Deferred ITCs 5 5 Rate refund 28 11 Other 39 34 Total deferred tax assets $ 1,456 $ 1,245 Net deferred tax liability $ 1,666 $ 1,949 (a) Prior periods have been reclassified to conform to current year presentation.

Fair Value of Financial Asset_2

Fair Value of Financial Assets and Liabilities (Tables)	12 Months Ended
	Dec. 31, 2022
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 billion and $1.3 billion as of Dec. 31, 2022 and 2021, respectively, and unrealized losses were $90 million and $7 million as of Dec. 31, 2022 and 2021, respectively. Non-derivative instruments with recurring fair value measurements in the nuclear decommissioning fund: 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. Dec. 31, 2021 Fair Value (Millions of Dollars) Cost Level 1 Level 2 Level 3 NAV Total Nuclear decommissioning fund (a) Cash equivalents $ 64 $ 64 $ — $ — $ — $ 64 Commingled funds 856 — — — 1,294 1,294 Debt securities 631 — 666 9 — 675 Equity securities 411 1,222 1 — — 1,223 Total $ 1,962 $ 1,286 $ 667 $ 9 $ 1,294 $ 3,256 (a) Reported in nuclear decommissioning fund and other investments on the consolidated balance sheets, which also includes $52 million of rabbi trust assets and other miscellaneous investments. For the years ended Dec. 31, 2022 and 2021, 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, 2022: 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 $ 6 $ 204 $ 250 $ 216 $ 676 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 $13 million at Dec. 31, 2022 and 2021, 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, 2022, 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, 2022, NSP-Minnesota had no 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, 2022 and 2021 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, 2022, 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, 2022 Dec. 31, 2021 MWh of electricity 44 57 MMBtu of natural gas 88 85 (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, 2022, six of NSP-Minnesota’s ten most significant counterparties for these activities, comprising $38 million or 34% 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 $28 million or 25% 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. One of these significant counterparties, comprising $47 million or 41% of this credit exposure, had credit quality less than investment grade, based on internal analysis. Four 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, 2022 and 2021, there were $4 million and $3 million, respectively, of derivative liabilities with such underlying contract provisions, respectively. Certain contracts also contain cross default provisions that may require the posting of collateral or settlement of the contracts if there was a failure under other financing arrangements related to payment terms or other covenants. As of Dec. 31, 2022 and 2021, there were approximately $76 million and $48 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, 2022 and 2021. Recurring Derivative Fair Value Measurements Impact of derivative activity: Pre-Tax Fair Value (Millions of Dollars) Accumulated Other Comprehensive Loss Regulatory (Assets) and Liabilities 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 $ — $ — Year Ended Dec. 31, 2020 Other derivative instruments Electric commodity $ — $ 2 Natural gas commodity — (2) 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, 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 Year Ended Dec. 31, 2020 Derivatives designated as cash flow hedges Interest rate $ 1 (a) $ — $ — Total $ 1 $ — $ — Other derivative instruments Commodity trading $ — $ — $ (5) (b) Electric commodity $ — $ (3) (c) $ — Natural gas commodity — 2 (d) (4) (d)(e) Total $ — $ (1) $ (9) (a) Recorded to interest charges. (b) Recorded to electric revenues. Presented amounts do not reflect non-derivative transactions or margin sharing with customers. (c) Recorded to electric fuel and purchased power. These derivative settlement gains and losses are shared with electric customers through fuel and purchased energy cost-recovery mechanisms and reclassified out of income as regulatory assets or liabilities, as appropriate. FTR settlements are shared with customers and do not have a material impact on net income. Presented amounts reflect changes in fair value between 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, 2022, 2021 and 2020. Derivative assets and liabilities measured at fair value on a recurring basis were as follows: Dec. 31, 2022 Dec. 31, 2021 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 $ 15 $ 38 $ 33 $ 86 $ (58) $ 28 $ 9 $ 40 $ 22 $ 71 $ (53) $ 18 Electric commodity — — 58 58 (2) 56 — — 30 30 (1) 29 Natural gas commodity — 5 — 5 — 5 — 6 — 6 — 6 Total current derivative assets $ 15 $ 43 $ 91 $ 149 $ (60) $ 89 $ 9 $ 46 $ 52 $ 107 $ (54) $ 53 Noncurrent derivative assets Other derivative instruments: Commodity trading $ 21 $ 40 $ 66 $ 127 $ (59) $ 68 $ 6 $ 34 $ 35 $ 75 $ (42) $ 33 Total noncurrent derivative assets $ 21 $ 40 $ 66 $ 127 $ (59) $ 68 $ 6 $ 34 $ 35 $ 75 $ (42) $ 33 Dec. 31, 2022 Dec. 31, 2021 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 Other derivative instruments: Commodity trading $ 23 $ 60 $ 6 $ 89 $ (63) $ 26 $ 13 $ 58 $ 4 $ 75 $ (58) $ 17 Electric commodity — — 2 2 (2) — — — 1 1 (1) — Natural gas commodity — 2 — 2 — 2 — 4 — 4 — 4 Total current derivative liabilities $ 23 $ 62 $ 8 $ 93 $ (65) 28 $ 13 $ 62 $ 5 $ 80 $ (59) 21 PPAs (b) 14 14 Current derivative instruments $ 42 $ 35 Noncurrent derivative liabilities Other derivative instruments: Commodity trading $ 37 $ 55 $ 42 $ 134 $ (60) $ 74 $ 15 $ 48 $ 26 $ 89 $ (53) $ 36 Total noncurrent derivative liabilities $ 37 $ 55 $ 42 $ 134 $ (60) 74 $ 15 $ 48 $ 26 $ 89 $ (53) 36 PPAs (b) 28 35 Noncurrent derivative instruments $ 102 $ 71 (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, 2022 and 2021, derivative assets and liabilities include no obligations to return cash collateral. At Dec. 31, 2022 and 2021, derivative assets and liabilities include rights to reclaim cash collateral of $6 million and $16 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) 2022 2021 2020 Balance at Jan. 1 $ 56 $ (11) $ 5 Purchases (a) 157 54 28 Settlements (a) (195) (82) (49) Net transactions recorded during the period: Gains (losses) recognized in earnings (b) 91 72 (8) Net gains (losses) recognized as regulatory assets and liabilities (a) (2) 23 13 Balance at Dec. 31 $ 107 $ 56 $ (11) (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: 2022 2021 (Millions of Dollars) Carrying Amount Fair Value Carrying Amount Fair Value Long-term debt, including current portion $ 6,942 $ 5,995 $ 6,747 $ 7,761 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, 2022 and 2021, 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, 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. Dec. 31, 2021 Fair Value (Millions of Dollars) Cost Level 1 Level 2 Level 3 NAV Total Nuclear decommissioning fund (a) Cash equivalents $ 64 $ 64 $ — $ — $ — $ 64 Commingled funds 856 — — — 1,294 1,294 Debt securities 631 — 666 9 — 675 Equity securities 411 1,222 1 — — 1,223 Total $ 1,962 $ 1,286 $ 667 $ 9 $ 1,294 $ 3,256 (a) Reported in nuclear decommissioning fund and other investments on the consolidated balance sheets, which also includes $52 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, 2022: 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 $ 6 $ 204 $ 250 $ 216 $ 676
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, 2022 Dec. 31, 2021 MWh of electricity 44 57 MMBtu of natural gas 88 85 (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 (Millions of Dollars) Accumulated Other Comprehensive Loss Regulatory (Assets) and Liabilities 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 $ — $ — Year Ended Dec. 31, 2020 Other derivative instruments Electric commodity $ — $ 2 Natural gas commodity — (2) 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, 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 Year Ended Dec. 31, 2020 Derivatives designated as cash flow hedges Interest rate $ 1 (a) $ — $ — Total $ 1 $ — $ — Other derivative instruments Commodity trading $ — $ — $ (5) (b) Electric commodity $ — $ (3) (c) $ — Natural gas commodity — 2 (d) (4) (d)(e) Total $ — $ (1) $ (9) (a) Recorded to interest charges. (b) Recorded to electric revenues. Presented amounts do not reflect non-derivative transactions or margin sharing with customers. (c) Recorded to electric fuel and purchased power. These derivative settlement gains and losses are shared with electric customers through fuel and purchased energy cost-recovery mechanisms and reclassified out of income as regulatory assets or liabilities, as appropriate. FTR settlements are shared with customers and do not have a material impact on net income. Presented amounts reflect changes in fair value between 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, 2022 Dec. 31, 2021 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 $ 15 $ 38 $ 33 $ 86 $ (58) $ 28 $ 9 $ 40 $ 22 $ 71 $ (53) $ 18 Electric commodity — — 58 58 (2) 56 — — 30 30 (1) 29 Natural gas commodity — 5 — 5 — 5 — 6 — 6 — 6 Total current derivative assets $ 15 $ 43 $ 91 $ 149 $ (60) $ 89 $ 9 $ 46 $ 52 $ 107 $ (54) $ 53 Noncurrent derivative assets Other derivative instruments: Commodity trading $ 21 $ 40 $ 66 $ 127 $ (59) $ 68 $ 6 $ 34 $ 35 $ 75 $ (42) $ 33 Total noncurrent derivative assets $ 21 $ 40 $ 66 $ 127 $ (59) $ 68 $ 6 $ 34 $ 35 $ 75 $ (42) $ 33 Dec. 31, 2022 Dec. 31, 2021 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 Other derivative instruments: Commodity trading $ 23 $ 60 $ 6 $ 89 $ (63) $ 26 $ 13 $ 58 $ 4 $ 75 $ (58) $ 17 Electric commodity — — 2 2 (2) — — — 1 1 (1) — Natural gas commodity — 2 — 2 — 2 — 4 — 4 — 4 Total current derivative liabilities $ 23 $ 62 $ 8 $ 93 $ (65) 28 $ 13 $ 62 $ 5 $ 80 $ (59) 21 PPAs (b) 14 14 Current derivative instruments $ 42 $ 35 Noncurrent derivative liabilities Other derivative instruments: Commodity trading $ 37 $ 55 $ 42 $ 134 $ (60) $ 74 $ 15 $ 48 $ 26 $ 89 $ (53) $ 36 Total noncurrent derivative liabilities $ 37 $ 55 $ 42 $ 134 $ (60) 74 $ 15 $ 48 $ 26 $ 89 $ (53) 36 PPAs (b) 28 35 Noncurrent derivative instruments $ 102 $ 71 (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, 2022 and 2021, derivative assets and liabilities include no obligations to return cash collateral. At Dec. 31, 2022 and 2021, derivative assets and liabilities include rights to reclaim cash collateral of $6 million and $16 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.
Changes in Level 3 Commodity Derivatives	Changes in Level 3 commodity derivatives: Year Ended Dec. 31 (Millions of Dollars) 2022 2021 2020 Balance at Jan. 1 $ 56 $ (11) $ 5 Purchases (a) 157 54 28 Settlements (a) (195) (82) (49) Net transactions recorded during the period: Gains (losses) recognized in earnings (b) 91 72 (8) Net gains (losses) recognized as regulatory assets and liabilities (a) (2) 23 13 Balance at Dec. 31 $ 107 $ 56 $ (11) (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	2022 2021 (Millions of Dollars) Carrying Amount Fair Value Carrying Amount Fair Value Long-term debt, including current portion $ 6,942 $ 5,995 $ 6,747 $ 7,761

Benefit Plans and Other Postr_2

Benefit Plans and Other Postretirement Benefits (Tables)	12 Months Ended
	Dec. 31, 2022
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) 2022 2021 2022 2021 Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost: Net loss $ 309 $ 307 $ 16 $ 31 Prior service credit — — (1) (4) Total $ 309 $ 307 $ 15 $ 27 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 $ 12 $ 25 $ — $ — Noncurrent regulatory assets 297 282 14 25 Deferred income taxes — — — 1 Net-of-tax accumulated other comprehensive income — — 1 1 Total $ 309 $ 307 $ 15 $ 27 Measurement date Dec 31, 2022 Dec 31, 2021 Dec 31, 2022 Dec 31, 2021
Projected Benefit Payments for the Pension and Postretirement Benefit Plans	Projected Benefit Payments NSP-Minnesota’s projected benefit payments: (Millions of Dollars) Projected Gross Projected Postretirement Health Care Benefit Payments (a) 2023 $ 84 $ 6 2024 64 5 2025 64 5 2026 61 5 2027 59 4 2028-2032 279 17 (a) Amount is reported net of expected Medicare Part D subsidies, which are immaterial.
Pension Plan
Benefit Plans and Other Postretirement Benefits [Abstract]
Target Asset Allocations and Plan Assets Measured at Fair Value	or each of the fair value hierarchy levels, NSP-Minnesota’s pension plan assets measured at fair value: Dec. 31, 2022 (a) Dec. 31, 2021 (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 $ 26 $ — $ — $ — $ 26 $ 31 $ — $ — $ — $ 31 Commingled funds 201 — — 201 402 304 — — 274 578 Debt securities — 129 1 — 130 — 219 1 — 220 Equity securities 11 — — — 11 16 — — — 16 Other — 1 — — 1 — 1 — 7 8 Total $ 238 $ 130 $ 1 $ 201 $ 570 $ 351 $ 220 $ 1 $ 281 $ 853 (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, 2022 (a) Dec. 31, 2021 (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 $ 2 $ — $ — $ — $ 1 $ 1 Debt securities — 2 — — 2 — 2 — — 2 Total $ 1 $ 3 $ — $ 1 $ 5 $ — $ 2 $ — $ 1 $ 3
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) 2022 2021 2022 2021 Change in Benefit Obligation: Obligation at Jan. 1 $ 877 $ 989 $ 64 $ 73 Service cost 27 30 — — Interest cost 25 25 2 2 Plan amendments 1 1 — — Actuarial gain (139) (28) (13) (5) Benefit payments (134) (140) (5) (6) Obligation at Dec. 31 $ 657 $ 877 $ 48 $ 64 Change in Fair Value of Plan Assets: Fair value of plan assets at Jan. 1 $ 853 $ 897 $ 3 $ 2 Actual return on plan assets (154) 62 — — Employer contributions 5 34 7 7 Benefit payments (134) (140) (5) (6) Fair value of plan assets at Dec. 31 $ 570 $ 853 $ 5 $ 3 Funded status of plans at Dec. 31 $ (87) $ (24) $ (43) $ (61) Amounts recognized in the Consolidated Balance Sheet at Dec. 31: Current liabilities $ — $ — $ (1) $ (3) Noncurrent liabilities (87) (24) (42) (58) Net amounts recognized $ (87) $ (24) $ (43) $ (61) Pension Benefits Postretirement Benefits Significant Assumptions Used to Measure Benefit Obligations: 2022 2021 2022 2021 Discount rate for year-end valuation 5.80 % 3.08 % 5.80 % 3.09 % Expected average long-term increase in compensation level 4.25 3.75 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 % 5.30 % Health care costs trend rate — initial: Post-65 N/A N/A 5.50 % 4.90 % 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 7 4
Components of Net Periodic Benefit Costs	Pension Benefits Postretirement Benefits (Millions of Dollars) 2022 2021 2020 2022 2021 2020 Service cost $ 27 $ 30 $ 27 $ — $ — $ — Interest cost 25 25 31 2 2 2 Expected return on plan assets (48) (52) (55) — — — Amortization of prior service cost — — — (3) (3) (3) Amortization of net loss 24 34 33 1 2 1 Settlement charge (a) 38 35 — — — — Net periodic pension cost 66 72 36 — 1 — Effects of regulation (32) (44) (4) — — — Net benefit cost recognized for financial reporting $ 34 $ 28 $ 32 $ — $ 1 $ — Significant Assumptions Used to Measure Costs: Discount rate 3.08 % 2.71 % 3.49 % 3.09 % 2.65 % 3.47 % Expected average long-term increase in compensation level 3.75 3.75 3.75 — — — Expected average long-term rate of return on assets 6.60 6.60 7.10 4.10 4.10 4.50 (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 2020.
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 2022 2021 2022 2021 Domestic and international equity securities 33 % 33 % 16 % 15 % Long-duration fixed income and interest rate swap securities 38 37 — — Short-to-intermediate fixed income securities 9 11 71 71 Alternative investments 18 17 12 8 Cash 2 2 1 6 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, 2022
Commitments and Contingencies Disclosure [Abstract]
Asset Retirement Obligations	NSP-Minnesota’s AROs were as follows: 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 Common 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. 2021 (Millions Jan. 1, 2021 Amounts Incurred (a) Accretion Cash Flow Revisions (b) Dec. 31, 2021 Electric Nuclear $ 1,957 $ — $ 99 $ — $ 2,056 Wind 270 101 13 — 384 Steam and other production 67 6 2 (2) 73 Distribution 16 — — — 16 Miscellaneous — — — — — Natural gas Transmission and distribution 39 — 2 14 55 Common Miscellaneous 1 — — — 1 Total liability $ 2,350 $ 107 $ 116 $ 12 $ 2,585 (a) Amounts incurred relate to the wind farms placed in service in 2021 (Blazing Star 2, Mower and Freeborn) and removal of a utility scale battery asset. (b) In 2021, AROs were revised for changes in timing and estimates of cash flows. 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, 2022 Dec. 31, 2021 PPAs $ 556 $ 556 Other 78 74 Gross operating lease ROU assets 634 630 Accumulated amortization (310) (222) Net operating lease ROU assets $ 324 $ 408
Lease, Cost [Table Text Block]	Components of lease expense: (Millions of Dollars) 2022 2021 2020 Operating leases PPA capacity payments $ 98 $ 96 $ 89 Other operating leases (a) 9 8 8 Total operating lease expense (b) $ 107 $ 104 $ 97 (a) Includes short-term lease expense o f $3 million, $2 million and $2 million for 2022, 2021 and 2020, respectively.
Lessee, Operating Lease, Liability, Maturity [Table Text Block]	Commitments under operating leases as of Dec. 31, 2022: (Millions of Dollars) PPA (a) (b) Operating Leases Other Operating Leases Total Leases 2023 $ 98 $ 12 $ 110 2024 100 7 107 2025 79 8 87 2026 40 7 47 2027 — 7 7 Thereafter — 24 24 Total minimum obligation 317 65 382 Interest component of obligation (19) (9) (28) Present value of minimum obligation $ 298 $ 56 354 Less current portion (98) Noncurrent operating lease liabilities $ 256 Weighted-average remaining lease term in years 7.6 (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 2026.
Estimated Minimum Purchases Under Fuel Contracts	Estimated minimum purchases for these contracts as of Dec. 31, 2022: (Millions of Dollars) Coal Nuclear fuel Natural gas Natural gas 2023 $ 227 $ 144 $ 130 $ 158 2024 110 112 1 148 2025 17 158 1 138 2026 1 37 — 143 2027 1 155 — 98 Thereafter — 194 — 116 Total (a) $ 356 $ 800 $ 132 $ 801 (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, 2022, 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) 2023 $ 61 $ 50 2024 63 45 2025 26 51 2026 9 48 2027 7 55 Thereafter 3 28 Total (b) $ 169 $ 277 (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, 2022
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: 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) Other comprehensive loss before reclassifications, net of taxes of $— $ — $ 1 $ 1 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) 2021 (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 $ (19) $ (3) $ (22) Losses reclassified from net accumulated other comprehensive loss: Amortization of interest rate hedges 2 (a) — 2 Net current period other comprehensive income 2 — 2 Accumulated other comprehensive loss at Dec. 31 $ (17) $ (3) $ (20) (a) Included in interest charges.

Segments and Related Informat_2

Segments and Related Information (Tables)	12 Months Ended
	Dec. 31, 2022
Segment Reporting [Abstract]
Results from Operations by Reportable Segment	NSP-Minnesota’s segment information: (Millions of Dollars) 2022 2021 2020 Regulated Electric Operating revenues — external (a) $ 5,617 $ 5,094 $ 4,571 Intersegment revenue 1 1 1 Total revenues $ 5,618 $ 5,095 $ 4,572 Depreciation and amortization 953 869 773 Interest charges and financing costs 257 240 221 Income tax (benefit) expense (127) (53) (14) Net income 626 566 553 Regulated Natural Gas Operating revenues — external (b) $ 1,022 $ 623 $ 493 Intersegment revenue 2 1 — Total revenues $ 1,024 $ 624 $ 493 Depreciation and amortization 60 56 51 Interest charges and financing costs 22 18 17 Income tax expense 14 6 7 Net income 45 29 30 All Other Total revenues $ 45 $ 39 $ 37 Depreciation and amortization 1 1 1 Income tax (benefit) expense 1 (1) 1 Net income 4 11 8 Consolidated Total Total revenues (a)(b) $ 6,687 $ 5,758 $ 5,102 Reconciling eliminations (3) (2) (1) Total operating revenues $ 6,684 $ 5,756 $ 5,101 Depreciation and amortization 1,014 926 825 Interest charges and financing costs 279 258 238 Income tax (benefit) expense (112) (48) (6) Net income 675 606 591 (a) Operating revenues include $514 million, $501 million and $440 million of affiliate electric revenue for the years ended Dec. 31, 2022, 2021 and 2020, respectively. See Note 13 for further information.

Related Party Transactions (Tab

Related Party Transactions (Tables)	12 Months Ended
	Dec. 31, 2022
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) 2022 2021 2020 Operating revenues: Electric $ 514 $ 501 $ 440 Gas — 1 1 Operating expenses: Purchased power 70 67 59 Transmission expense 132 121 109 Other operating expenses — paid to Xcel Energy Services Inc. 673 615 584 Interest income 1 — — Interest expense 1 — — Accounts receivable and payable with affiliates at Dec. 31: 2022 2021 (Millions of Dollars) Accounts Receivable Accounts Payable Accounts Receivable Accounts Payable NSP-Wisconsin $ 4 $ — $ 13 $ — PSCo — 2 16 — SPS — 3 — 2 Other subsidiaries of Xcel Energy Inc. 41 84 — 61 $ 45 $ 89 $ 29 $ 63

Summary of Significant Accoun_4

Summary of Significant Accounting Policies (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Property, Plant and Equipment [Abstract]
Depreciation expense expressed as a percentage of average depreciable property	4%	3.70%	3.70%
Nuclear Decommissioning [Abstract]
Studies timeframe	3 years
Accounts and Financing Receivable, after Allowance for Credit Loss, Current and Noncurrent [Abstract]
Allowance for bad debts	$ 46	$ 45
Alternative Revenue Programs [Abstract]
maximum number of months following annual period	24 months
Public Utilities, Inventory [Line Items]
Public Utilities, Inventory	$ 384	309
maturity period	3 months
Studies timeframe	3 years
maximum number of months following annual period	24 months
Supplies
Public Utilities, Inventory [Line Items]
Public Utilities, Inventory	$ 200	181
Public Utilities, Inventory, Fuel
Public Utilities, Inventory [Line Items]
Public Utilities, Inventory	103	81
Public Utilities, Inventory, Natural Gas
Public Utilities, Inventory [Line Items]
Public Utilities, Inventory	$ 81	$ 47

Accounting Pronouncements - Rec

Accounting Pronouncements - Recently Adopted (Details) $ in Millions	12 Months Ended
	Dec. 31, 2020 USD ($)
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Credit Losses, Topic 326 (ASC Topic 326)	$ 1
Retained Earnings
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Credit Losses, Topic 326 (ASC Topic 326)	$ 1

Property Plant and Equipment (D

Property Plant and Equipment (Details) - USD ($) $ in Millions		Dec. 31, 2022	Dec. 31, 2021
Property, Plant and Equipment [Line Items]
Property, plant and equipment		$ 24,923	$ 23,728
Accumulated depreciation and amortization		7,734	7,606
Property, Plant and Equipment, Net		17,478	16,430
Electric plant
Property, Plant and Equipment [Line Items]
Property, plant and equipment		20,114	19,154
Natural gas plant
Property, Plant and Equipment [Line Items]
Property, plant and equipment		2,100	1,864
Common and other property
Property, Plant and Equipment [Line Items]
Property, plant and equipment		1,156	1,007
Plant to be Retired [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	[1]	646	719
CWIP
Property, Plant and Equipment [Line Items]
Property, plant and equipment		907	984
Nuclear fuel
Property, Plant and Equipment [Line Items]
Property, plant and equipment		3,183	3,081
Accumulated depreciation and amortization		$ 2,894	$ 2,773
[1]Amounts include regulator-approved retirements of Sherco Units 1, 2 and 3 and A.S. King and are 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, 2022 USD ($)
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	$ 1,686	[1]
Accumulated Depreciation	715	[1]
CWIP	4
Electric Generation | Sherco Unit 3
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	623
Accumulated Depreciation	$ 468
Percent Owned	59%
Electric Generation | Sherco Common Facilities Units 1, 2 and 3
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	$ 180
Accumulated Depreciation	$ 115
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	$ 3
Percent Owned	50%
Electric Transmission | Huntley Wilmarth
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	$ 49
Accumulated Depreciation	$ 1
Percent Owned	50%
Electric Transmission | CapX2020 Transmission
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	$ 818
Accumulated Depreciation	$ 124
Percent Owned	51%
[1]Projects additionally include $4 million in CWIP.

Regulatory Assets and Liabili_3

Regulatory Assets and Liabilities, Regulatory Assets (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2022	Dec. 31, 2021
Regulatory Assets [Line Items]
Regulatory Asset, Current		$ 384	$ 527
Regulatory assets		(894)	(718)
Regulatory assets not currently earning a return		369	691
Pension and Retiree Medical Obligations
Regulatory Assets [Line Items]
Regulatory Asset, Current		12	24	[1]
Regulatory assets		(347)	(301)	[1]
Excess deferred taxes - TCJA
Regulatory Assets [Line Items]
Regulatory Asset, Current		10	10	[1]
Regulatory assets		(103)	(113)	[1]
Recoverable Deferred Taxes on AFUDC Recorded in Plant
Regulatory Assets [Line Items]
Regulatory Asset, Current		0	0	[1]
Regulatory assets		(112)	(114)	[1]
Benson purchase power agreement termination and asset purchase
Regulatory Assets [Line Items]
Regulatory Asset, Current		10	10	[1]
Regulatory assets		$ (45)	(55)	[1]
Regulatory Asset, Amortization Period		6 years
PI extended power update
Regulatory Assets [Line Items]
Regulatory Asset, Current		$ 4	4	[1]
Regulatory assets		$ (42)	(46)	[1]
Regulatory Asset, Amortization Period		12 years
Contract Valuation Adjustments
Regulatory Assets [Line Items]
Regulatory Asset, Current	[2]	$ 16	18	[1]
Regulatory assets	[2]	(28)	(34)	[1]
Laurentian biomass PPA termination
Regulatory Assets [Line Items]
Regulatory Asset, Current		18	18	[1]
Regulatory assets		$ 0	(18)	[1]
Laurentian biomass PPA termination | Minimum [Member]
Regulatory Assets [Line Items]
Regulatory Asset, Amortization Period		1 year
Purchased Power Agreements
Regulatory Assets [Line Items]
Regulatory Asset, Current		$ 7	6	[1]
Regulatory assets		(19)	(27)	[1]
Sales True-Up and Revenue Decoupling
Regulatory Assets [Line Items]
Regulatory Asset, Current		53	33	[1]
Regulatory assets		$ 0	(56)	[1]
Sales True-Up and Revenue Decoupling | Minimum [Member]
Regulatory Assets [Line Items]
Regulatory Asset, Amortization Period		1 year
Conservation Programs
Regulatory Assets [Line Items]
Regulatory Asset, Current	[3]	$ 6	7	[1]
Regulatory assets	[3]	$ (19)	(22)	[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
Deferred Purchased Natural Gas and Electric Energy Costs
Regulatory Assets [Line Items]
Regulatory Asset, Current		$ 110	138	[1]
Regulatory assets		$ (65)	(190)	[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		5 years
Loss on Reacquired Debt
Regulatory Assets [Line Items]
Regulatory Asset, Current		$ 1	1	[1]
Regulatory assets		(10)	(11)	[1]
Nuclear Refueling Outage Costs
Regulatory Assets [Line Items]
Regulatory Asset, Current		30	37	[1]
Regulatory assets		$ (12)	(16)	[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
Renewable Resources and Environmental Initiatives
Regulatory Assets [Line Items]
Regulatory Asset, Current		$ 50	170	[1]
Regulatory assets		$ 0	(3)	[1]
Renewable Resources and Environmental Initiatives | Minimum [Member]
Regulatory Assets [Line Items]
Regulatory Asset, Amortization Period		1 year
Gas Pipeline Inspection and Remediation Costs
Regulatory Assets [Line Items]
Regulatory Asset, Current		$ 42	33	[1]
Regulatory assets		$ 0	0	[1]
Gas Pipeline Inspection and Remediation Costs | Minimum [Member]
Regulatory Assets [Line Items]
Regulatory Asset, Amortization Period		1 year
Net AROs
Regulatory Assets [Line Items]
Regulatory Asset, Current	[4]	$ 0	0	[1]
Regulatory assets	[4]	(62)	(316)	[1]
Other
Regulatory Assets [Line Items]
Regulatory Asset, Current		15	18	[1]
Regulatory assets		$ (30)	$ (28)	[1]
[1]Prior period amounts have been restated to conform with current year presentation.[2]Includes the fair value of certain long-term PPAs used to meet energy capacity requirements and valuation adjustments on natural gas commodity purchases.[3]Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions[4]Includes amounts recorded for future recovery of AROs, less amounts recovered through nuclear decommissioning accruals and gains from decommissioning investments.

Regulatory Assets and Liabili_4

Regulatory Assets and Liabilities, Regulatory Liabilities (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2022	Dec. 31, 2021
Regulatory Liabilities [Line Items]
Regulatory Liability, Current	[1]	$ 191	$ 117
Regulatory Liability, Noncurrent	[1]	$ 1,983	1,927
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]	$ 6	9	[3]
Regulatory Liability, Noncurrent	[2]	1,200	1,256	[3]
Plant Removal Costs
Regulatory Liabilities [Line Items]
Regulatory Liability, Current		0	0	[3]
Regulatory Liability, Noncurrent		693	613	[3]
Investment Tax Credit Deferrals
Regulatory Liabilities [Line Items]
Regulatory Liability, Current		0	0	[3]
Regulatory Liability, Noncurrent		17	7	[3]
Contract Valuation Adjustments
Regulatory Liabilities [Line Items]
Regulatory Liability, Current	[4]	56	29	[3]
Regulatory Liability, Noncurrent	[4]	$ 0	0	[3]
Contract Valuation Adjustments | Minimum [Member]
Regulatory Liabilities [Line Items]
Regulatory Liability, Amortization Period		1 year
DOE Settlement
Regulatory Liabilities [Line Items]
Regulatory Liability, Current		$ 0	14	[3]
Regulatory Liability, Noncurrent		0	0	[3]
Deferred Electric Energy Costs
Regulatory Liabilities [Line Items]
Regulatory Liability, Current		26	14	[3]
Regulatory Liability, Noncurrent		0	0	[3]
Renewable Resources and Environmental Initiatives
Regulatory Liabilities [Line Items]
Regulatory Liability, Current		6	1	[3]
Regulatory Liability, Noncurrent		19	10	[3]
Other Regulatory Liabilities
Regulatory Liabilities [Line Items]
Regulatory Liability, Current		49	46	[3]
Regulatory Liability, Noncurrent		23	34	[3]
Revenue Decoupling
Regulatory Liabilities [Line Items]
Regulatory Liability, Current		0	0	[3]
Regulatory Liability, Noncurrent		22	0	[3]
Formula Rates
Regulatory Liabilities [Line Items]
Regulatory Liability, Current		6	4	[3]
Regulatory Liability, Noncurrent		$ 9	7	[3]
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
Conservation Programs
Regulatory Liabilities [Line Items]
Regulatory Liability, Current		$ 42	0	[3]
Regulatory Liability, Noncurrent		$ 0	0	[3]
Conservation Programs | Minimum [Member]
Regulatory Liabilities [Line Items]
Regulatory Liability, Amortization Period		1 year
Other Current Liabilities
Regulatory Liabilities [Line Items]
Entity's Recorded Provision for Revenue Subject To Refund		$ 67	$ 15
[1]Revenue subject to refund of $67 million and $15 million for 2022 and 2021, respectively, is included in other current liabilities.[2]Includes the revaluation of recoverable/regulated plant accumulated deferred income taxes and revaluation impact of non-plant accumulated deferred income taxes due to the TCJA.[3]Prior period amounts have been restated to conform with current year presentation.[4]Includes the fair value of FTR instruments utilized/intended to offset the impacts of transmission system congestion

Short-Term Debt (Details)

Short-Term Debt (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Short-term Debt [Line Items]
Short-term Debt	$ 207	$ 207	$ 0
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	0	0	6	3
Short-term Debt, Maximum Amount Outstanding During Period	$ 4	$ 4	$ 236	$ 116
Line of Credit Facility, Interest Rate During Period	3.87%	3.87%	0.07%	1.53%
Commercial Paper [Member]
Short-term Debt [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	$ 700	$ 700	$ 500	$ 500
Short-term Debt	207	207	0	179
Short-term Debt, Average Outstanding Amount	81	21	26	10
Short-term Debt, Maximum Amount Outstanding During Period	$ 290	$ 290	$ 317	$ 179
Short-term Debt, Weighted Average Interest Rate, at Point in Time				0.18%
Line of Credit Facility, Interest Rate During Period	4.32%	4.14%	0.18%	1.25%

Letters of Credit (Details)

Letters of Credit (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Line of Credit Facility [Line Items]
Short-term Debt	$ 207	$ 0
Letter of Credit [Member]
Line of Credit Facility [Line Items]
Short-term Debt	$ 15	$ 9
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	$ 54

Credit Facilities (Details)

Credit Facilities (Details) $ in Millions		12 Months Ended
		Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)
Line of Credit Facility [Line Items]
Short-term Debt		$ 207	$ 0
Letter of Credit [Member]
Line of Credit Facility [Line Items]
Short-term Debt		15	$ 9
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		$ 54
Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Line Of Credit Facility Debt To Total Capitalization Ratio (as a percent)	[1]	48%	47%
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]	222
Line of Credit Facility, Remaining Borrowing Capacity		478
Direct advances on the credit facility outstanding		$ 0	$ 0
[1]The credit facility has a financial covenant requiring that the debt-to-total capitalization ratio be less than or equal to 65%.[2]All extension requests are subject to majority bank group approval.[3]This credit facility matures in September 2027.[4]Includes outstanding commercial paper and letters of credit.

Long-Term Debt (Details)

Long-Term Debt (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2022	Dec. 31, 2021
Long-Term Borrowings and Other Financing Instruments
Unamortized discount		$ (45)	$ (44)
Unamortized debt expense		(66)	(62)
Long-term Debt, Current Maturities		400	300
Long-term Debt		6,542	6,447
2023		400
2024		0
2025		250
2026		0
2027		0
First Mortgage Bonds | Series Due Aug. 15, 2022 [Member]
Long-Term Borrowings and Other Financing Instruments
Face Amount		$ 0	300
Debt Instrument, Interest Rate, Stated Percentage		2.15%
First Mortgage Bonds | Series Due May 15, 2023 [Member]
Long-Term Borrowings and Other Financing Instruments
Face Amount		$ 400	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	[1]	$ 425	425
Debt Instrument, Interest Rate, Stated Percentage	[1]	2.25%
First Mortgage Bonds | Series Due July 15, 2035 [Domain]
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 [Domain]
Long-Term Borrowings and Other Financing Instruments
Face Amount		$ 400	400
Debt Instrument, Interest Rate, Stated Percentage		6.25%
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 March 1, 2050 [Domain]
Long-Term Borrowings and Other Financing Instruments
Face Amount		$ 600	600
Debt Instrument, Interest Rate, Stated Percentage		2.90%
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	[1]	$ 425	425
Debt Instrument, Interest Rate, Stated Percentage	[1]	3.20%
First Mortgage Bonds | Series Due June 1, 2052
Long-Term Borrowings and Other Financing Instruments
Face Amount	[2]	$ 500	0
Debt Instrument, Interest Rate, Stated Percentage	[2]	4.50%
Long-term Debt
Long-Term Borrowings and Other Financing Instruments
Face Amount		$ 3	$ 3
Letter of Credit [Member]
Long-Term Borrowings and Other Financing Instruments
Line of Credit Facility, Expiration Period		1 year
[1]2021 financing.[2]2022 financing.

Deferred Financing Costs (Detai

Deferred Financing Costs (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Deferred Financing Costs [Abstract]
Deferred Finance Costs, Noncurrent, Net	$ 66	$ 62

Dividend and Other Capital-Rela

Dividend and Other Capital-Related Restrictions (Details) $ in Millions	Dec. 31, 2022 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	$ 1,446
Capitalization, Short term debt, long term debt and equity	14,984
Maximum total capitalization	$ 16,140

Revenues Revenues (Details)

Revenues Revenues (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Total revenue from contracts with customers
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	$ 6,368	$ 5,320	$ 4,732
Retail
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	4,865	4,114	3,830
Retail | Residential
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	2,011	1,722	1,667
Retail | C&I
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	2,809	2,353	2,124
Retail | Other
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	45	39	39
Wholesale
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	668	442	202
Transmission
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	287	242	238
Interchange
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	514	501	440
Other
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	34	21	22
Alternative and Other [Member]
Disaggregation of Revenue [Line Items]
Alternative revenue and other	316	436	369
Regulated Electric | Total revenue from contracts with customers
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	5,361	4,706	4,238
Regulated Electric | Retail
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	3,877	3,514	3,343
Regulated Electric | Retail | Residential
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	1,463	1,374	1,375
Regulated Electric | Retail | C&I
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	2,376	2,107	1,935
Regulated Electric | Retail | Other
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	38	33	33
Regulated Electric | Wholesale
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	668	442	202
Regulated Electric | Transmission
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	287	242	238
Regulated Electric | Interchange
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	514	501	440
Regulated Electric | Other
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	15	7	15
Regulated Electric | Alternative and Other [Member]
Disaggregation of Revenue [Line Items]
Alternative revenue and other	256	388	333
Regulated Natural Gas | Total revenue from contracts with customers
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	962	575	457
Regulated Natural Gas | Retail
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	943	561	450
Regulated Natural Gas | Retail | Residential
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	510	315	261
Regulated Natural Gas | Retail | C&I
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	433	246	189
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	19	14	7
Regulated Natural Gas | Alternative and Other [Member]
Disaggregation of Revenue [Line Items]
Alternative revenue and other	60	48	36
All Other | Total revenue from contracts with customers
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	45	39	37
All Other | Retail
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	45	39	37
All Other | Retail | Residential
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	38	33	31
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	6	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	6,684	5,756	5,101
Total revenues | Regulated Electric
Disaggregation of Revenue [Line Items]
Total revenues	5,617	5,094	4,571
Total revenues | Regulated Natural Gas
Disaggregation of Revenue [Line Items]
Total revenues	1,022	623	493
Total revenues | All Other
Disaggregation of Revenue [Line Items]
Total revenues	$ 45	$ 39	$ 37

Federal Loss Carryback

Federal Loss Carryback $ in Millions	12 Months Ended
	Dec. 31, 2022 USD ($)
Income Tax Disclosure [Abstract]
Tax Adjustments, Settlements, and Unusual Provisions	$ 13

Unrecognized Tax Benefits

Unrecognized Tax Benefits - USD ($)	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Income Tax Disclosure [Abstract]
Unrecognized tax benefit — Permanent tax positions	$ 31,000,000	$ 23,000,000
Unrecognized tax benefit — Temporary tax positions	3,000,000	3,000,000
Total unrecognized tax benefit	34,000,000	26,000,000	$ 24,000,000	$ 20,000,000
Additions based on tax positions related to the current year	2,000,000	2,000,000	2,000,000
Reductions based on tax positions related to the current year	0	0	0
Additions for tax positions of prior years	6,000,000	0	16,000,000
Reductions for tax positions of prior years	0	0	(14,000,000)
NOL and tax credit carryforwards	(13,000,000)	(13,000,000)
Decrease in Unrecognized Tax Benefits is Reasonably Possible	22,000,000
Unrecognized Tax Benefits, Income Tax Penalties Expense	0	0
Payable for interest related to unrecognized tax benefits at Jan. 1	(3,000,000)	(2,000,000)	(2,000,000)	$ (2,000,000)
Interest expense related to unrecognized tax benefits	$ (1,000,000)	$ 0	$ 0

Other Income Tax Matters

Other Income Tax Matters - USD ($) $ in Millions		3 Months Ended	12 Months Ended
		Dec. 31, 2022	Dec. 31, 2022	Dec. 31, 2021		Dec. 31, 2020
Income Tax [Line Items]
Federal NOL carryforward		$ 2	$ 2	$ 77
Federal tax credit carryforwards		909	909	704
State NOL carryforwards		184	184	344
Valuation allowances for state NOL carryforwards		(1)	(1)	(1)
state tax credit carryforward, net of federal detirment	[1]	68	68	78
valuation allowances for state credit carryforwards, net of federal benefit	[2]	$ (58)	$ (58)	$ (64)
Federal statutory rate			21%	21%	[3]	21%	[3]
State income tax on pretax income, net of federal tax effect			7%	7%	[3]	7%	[3]
Effective Income Tax Rate Reconciliation, Tax Credit, Percent	[4]		(39.60%)	(27.80%)	[3]	(19.30%)	[3]
Plant regulatory differences (b)	[5]		(6.70%)	(8.10%)	[3]	(7.20%)	[3]
Other tax credits, net NOL & tax credit allowances			(1.30%)	(1.40%)	[3]	(1.20%)	[3]
NOL Carryback		0%		0%	[3]	(2.10%)	[3]
Other, net			(0.30%)	0.70%	[3]	0.80%	[3]
Effective income tax rate			(19.90%)	(8.60%)	[3]	(1.00%)	[3]
Income tax benefit			$ (112)	$ (48)		$ (6)
Deferred tax (benefit) expense excluding items below			(283)	109		61
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities			70	(145)		(127)
Tax expense allocated to other comprehensive income, and other			(1)	0		(1)
Deferred tax benefit		$ (214)	(214)	(36)		(67)
Deferred fuel costs		49	49	92	[6]
Present value of minimum obligation		354	354
income tax expense [Member]
Income Tax [Line Items]
Current federal tax expense (benefit)			70	(10)		41
Current state tax expense (benefit)			26	(1)		12
Current change in unrecognized tax expense			8	1		9
Deferred federal tax benefit			(237)	(87)		(102)
Deferred state tax expense			23	49		38
Deferred change in unrecognized tax expense (benefit)			0	2		(3)
Deferred ITCs			(2)	(2)		(1)
Income tax benefit			(112)	(48)		$ (6)
Net Deferred Tax Liablility [Member]
Income Tax [Line Items]
Federal tax credit carryforwards		977	977	782	[6]
Deferred ITCs			5	5	[6]
Deferred tax benefit		(1,456)	(1,456)	(1,245)	[6]
Differences between book and tax bases of property			2,708	2,679	[6]
Regulatory assets		189	189	214	[6]
Operating lease assets		98	98	123	[6]
Pension expense		68	68	73	[6]
Other		10	10	13	[6]
Total deferred tax liabilities		3,122	3,122	3,194	[6]
Regulatory Liabilities		325	325	279	[6]
Present value of minimum obligation		98	98	123	[6]
NOL and tax credit valuation allowances		(58)	(58)	(64)	[6]
Other employee benefits		27	27	32	[6]
NOL carryforward		15	15	43	[6]
Other		39	39	34	[6]
Net deferred tax liability		1,666	1,666	1,949	[6]
Deferred Tax Assets Rate Refund		28	28	11
State and Local Jurisdiction
Income Tax [Line Items]
Federal detriment		18	18	21
Federal Benefit		$ 15	$ 15	$ 17
[1]State tax credit carryforwards are net of federal detriment of $18 million and $21 million as of Dec. 31, 2022 and 2021, respectively.[2]Valuation allowances for state tax credit carryforwards were net of federal benefit of $15 million and $17 million as of Dec. 31, 2022 and 2021, respectively.[3]Prior period amounts have been restated to conform with current year presentation.[4] Wind PTCs are credited to customers (reduction to revenue) and do not materially impact net income.

Nuclear Decommissioning Fund (D

Nuclear Decommissioning Fund (Details) - USD ($) $ in Millions	Dec. 31, 2022		Dec. 31, 2021
Investments [Abstract]
Miscellaneous investments	$ 48		$ 52
Final Contractual Maturity [Abstract]
Due in 1 Year or Less	(6)
Due in 1 to 5 Years	204
Due in 5 to 10 Years	250
Due after 10 Years	216
Total	676
Fair Value Measured on a Recurring Basis | Cost
Investments [Abstract]
Decommissioning Fund Investments	1,976	[1]	1,962	[2]
Fair Value Measured on a Recurring Basis | Cost | Cash equivalents
Investments [Abstract]
Cash equivalents	29	[1]	64	[2]
Fair Value Measured on a Recurring Basis | Cost | Commingled Funds
Investments [Abstract]
Investments, Fair Value Disclosure	803	[1]	856	[2]
Fair Value Measured on a Recurring Basis | Cost | Debt Securities [Member]
Investments [Abstract]
Debt Securities, Available-for-Sale, Excluding Accrued Interest	738	[1]	631	[2]
Fair Value Measured on a Recurring Basis | Cost | Equity Securities
Investments [Abstract]
Equity Securities, FV-NI, Current	406	[1]	411	[2]
Fair Value Measured on a Recurring Basis | Fair Value
Investments [Abstract]
Alternative Investment	1,178	[1]	1,294	[2]
Decommissioning Fund Investments	2,882	[1]	3,256	[2]
Fair Value Measured on a Recurring Basis | Fair Value | Cash equivalents
Investments [Abstract]
Cash equivalents	29	[1]	64	[2]
Alternative Investment	0	[1]	0	[2]
Fair Value Measured on a Recurring Basis | Fair Value | Commingled Funds
Investments [Abstract]
Alternative Investment	1,178	[1]	1,294	[2]
Investments, Fair Value Disclosure	1,178	[1]	1,294	[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	675	[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	1,000	[1]	1,223	[2]
Fair Value Measured on a Recurring Basis | Fair Value | Level 1
Investments [Abstract]
Decommissioning Fund Investments	1,028	[1]	1,286	[2]
Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | Cash equivalents
Investments [Abstract]
Cash equivalents	29	[1]	64	[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	999	[1]	1,222	[2]
Fair Value Measured on a Recurring Basis | Fair Value | Level 2
Investments [Abstract]
Decommissioning Fund Investments	670	[1]	667	[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	669	[1]	666	[2]
Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | Equity Securities
Investments [Abstract]
Equity Securities, FV-NI, Current	1	[1]	1	[2]
Fair Value Measured on a Recurring Basis | Fair Value | Level 3
Investments [Abstract]
Decommissioning Fund Investments	6	[1]	9	[2]
Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | Cash equivalents
Investments [Abstract]
Cash equivalents	0	[1]	0	[2]
Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | Commingled Funds
Investments [Abstract]
Investments, Fair Value Disclosure	0	[1]	0	[2]
Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | Debt Securities [Member]
Investments [Abstract]
Debt Securities, Available-for-Sale, Excluding Accrued Interest	6	[1]	9	[2]
Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | Equity Securities
Investments [Abstract]
Equity Securities, FV-NI, Current	0	[1]	0	[2]
Nuclear Decommissioning Fund [Member] | Fair Value Measured on a Recurring Basis | Fair Value
Investments [Abstract]
Decommissioning Fund Investments	$ 2,900		$ 3,300
[1]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.[2]Reported in nuclear decommissioning fund and other investments on the consolidated balance sheets, which also includes $52 million of rabbi trust assets and other miscellaneous investments.

Rabbi Trust (Details)

Rabbi Trust (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022		Dec. 31, 2021
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt Securities, Available-for-Sale, Unrealized Gain	$ 1,000		$ 1,300
Debt Securities, Available-for-Sale, Unrealized Loss	90		7
Fair Value Measured on a Recurring Basis | Cost | Cash
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	29	[1]	64	[2]
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	29	[1]	64	[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	29	[1]	64	[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]
Rabbi Trust [Member] | Fair Value Measured on a Recurring Basis | Fair Value
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total	$ 12		$ 13
[1]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.[2]Reported in nuclear decommissioning fund and other investments on the consolidated balance sheets, which also includes $52 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, 2022 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	$ 0

Commodity Derivatives (Details)

Commodity Derivatives (Details) MWh in Millions, MMBTU in Millions		Dec. 31, 2022 MWh MMBTU	Dec. 31, 2021 MMBTU MWh
Electric Commodity
Derivative [Line Items]
Notional amount | MWh	[1],[2]	44	57
Natural Gas Commodity
Derivative [Line Items]
Notional amount | MMBTU	[1],[2]	88	85
[1]Not reflective of net positions in the underlying commodities.[2]Notional amounts for options included on a gross basis, but are weighted for the probability of exercise.

Consideration of Credit Risk an

Consideration of Credit Risk and Concentrations (Details) - Credit Concentration Risk $ in Millions	Dec. 31, 2022 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	4
External Credit Rating, Investment Grade
Derivative [Line Items]
Number of most significant counterparties	6
Credit exposure for the most significant counterparties | $	$ 38
Percentage of credit exposure for the most significant counterparties	34%
Internal Investment Grade [Member]
Derivative [Line Items]
Number of most significant counterparties	3
Credit exposure for the most significant counterparties | $	$ 28
Percentage of credit exposure for the most significant counterparties	25%
External Credit Rating, Non Investment Grade
Derivative [Line Items]
Number of most significant counterparties	1
Credit exposure for the most significant counterparties | $	$ 47
Percentage of credit exposure for the most significant counterparties	41%

Qualifying Cash Flow Hedges (De

Qualifying Cash Flow Hedges (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Financial Impact of Qualifying Cash Flow Hedges on Accumulated Other Comprehensive Income (Loss) [Roll Forward]
After-tax net realized losses on derivative transactions reclassified into earnings		$ 1	$ 2	$ 1
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		7	0	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)		3	2	1
Derivative, Gain (Loss) on Derivative, Net		9	45	(9)
Electric Commodity Contract | Other Derivative Instruments
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract]
Pre-tax fair value gains (losses) recognized during the period in accumulated other comprehensive loss		0	0	0
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities		7	(3)	(2)
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]	1	3	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		0	3	2
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]	(2)	(1)	2
Derivative, Gain (Loss) on Derivative, Net	[2],[3]	(8)	(6)	(4)
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]	17	51	(5)
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 (gains) losses reclassified into income during the period from accumulated other comprehensive loss		1	2	1
Pre-tax gains (losses) reclassified into income during the period from regulatory assets and (liabilities)		0	0	0
Derivative, Gain (Loss) on Derivative, Net		0	0	0
Cash Flow Hedges | Interest Rate Contract | Designated as Hedging Instrument
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract]
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss	[5]	1	2	1
Pre-tax gains (losses) reclassified into income during the period from regulatory assets and (liabilities)		0	0	0
Derivative, Gain (Loss) on Derivative, Net		$ 0	$ 0	$ 0
[1]Recorded to electric fuel and purchased power. These derivative settlement gains and losses are shared with electric customers through fuel and purchased energy cost-recovery mechanisms and reclassified out of income as regulatory assets or liabilities, as appropriate. FTR settlements are shared with customers and do not have a material impact on net income. Presented amounts reflect changes in fair value between auction and settlement dates, but exclude the original auction fair value.[2]Recorded to cost of natural gas sold and transported. These losses are subject to cost-recovery mechanisms and reclassified out of income to a regulatory asset, as appropriate.[3]Relates primarily to option premium amortization.[4]Recorded to electric revenues. Presented amounts do not reflect non-derivative transactions or margin sharing with customers.[5]Recorded to interest charges.

Credit Related Contingent Featu

Credit Related Contingent Features (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Fair Value Disclosures [Abstract]
Derivative instruments in a gross liability position	$ 4	$ 3
Derivative, Gross Liability with Cross Default Position, Aggregate Fair Value	$ 76	$ 48

Recurring Fair Value Measuremen

Recurring Fair Value Measurements (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Derivatives, Fair Value [Line Items]
Derivative Asset, Noncurrent, Statement of Financial Position [Extensible Enumeration]		Other Assets, Noncurrent	Other Assets, Noncurrent
Derivative Liability, Current		$ 42	$ 35
Derivative Liability, Net		$ 102	$ 71
Derivative Liability, Noncurrent, Statement of Financial Position [Extensible Enumeration]		Other Liabilities, Noncurrent	Other Liabilities, Noncurrent
Return Cash Collateral		$ 0	$ 0
Reclaim Cash Collateral		$ 6	$ 16
Derivative Asset, Current, Statement of Financial Position [Extensible Enumeration]		Derivative instruments	Derivative instruments
Derivative Liability, Current, Statement of Financial Position [Extensible Enumeration]		Other Liabilities, Current	Other 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		$ 56	$ (11)	$ 5
Purchases	[1]	157	54	28
Settlements	[1]	(195)	(82)	(49)
Gains (losses) recognized in earnings	[2]	91	72	(8)
Net gains (losses) recognized as regulatory assets and liabilities	[1]	(2)	23	13
Balance at end of period		107	56	$ (11)
Fair Value Measured on a Recurring Basis
Derivatives, Fair Value [Line Items]
Derivative Asset, Current		89	53
Derivative Asset, Net		68	33
Derivative Liability, Current		28	21
Derivative Liability, Net		74	36
Fair Value Measured on a Recurring Basis | Other Derivative Instruments | Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Current		28	18
Derivative Asset, Net		68	33
Derivative Liability, Current		26	17
Derivative Liability, Net		74	36
Fair Value Measured on a Recurring Basis | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		58	30
Netting	[3]	(2)	(1)
Derivative Asset, Current		56	29
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
Fair Value Measured on a Recurring Basis | Other Derivative Instruments | Electric Commodity | Level 3
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		58	30
Fair Value Measured on a Recurring Basis | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		5	6
Netting	[3]	0	0
Derivative Asset, Current		5	6
Derivative Liability, Current		2	4
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	6
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 | Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		149	107
Netting	[3]	(60)	(54)
Fair Value Measured on a Recurring Basis | Other Current Assets | Level 1
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		15	9
Fair Value Measured on a Recurring Basis | Other Current Assets | Level 2
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		43	46
Fair Value Measured on a Recurring Basis | Other Current Assets | Level 3
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		91	52
Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments | Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		86	71
Netting	[3]	(58)	(53)
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		15	9
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		38	40
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		33	22
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		127	75
Netting	[3]	(59)	(42)
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets | Level 1
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		21	6
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets | Level 2
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		40	34
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets | Level 3
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		66	35
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets | Other Derivative Instruments | Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		127	75
Netting	[3]	(59)	(42)
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		21	6
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		40	34
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		66	35
Fair Value Measured on a Recurring Basis | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		93	80
Netting	[3]	(65)	(59)
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Level 1
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		23	13
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Level 2
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		62	62
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Level 3
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		8	5
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		89	75
Netting	[3]	(63)	(58)
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		23	13
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	58
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		6	4
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		2	1
Netting	[3]	(2)	(1)
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		2	1
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		2	4
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		2	4
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 Noncurrent Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		134	89
Netting	[3]	(60)	(53)
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities | Level 1
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		37	15
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities | Level 2
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		55	48
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities | Level 3
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		42	26
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities | Other Derivative Instruments | Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		134	89
Netting	[3]	(60)	(53)
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		37	15
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		55	48
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		42	26
Fair Value, Measurements, Nonrecurring | Purchased Power Agreements
Derivatives, Fair Value [Line Items]
Derivative Liability, Current	[4]	14	14
Derivative Liability, Net	[4]	$ 28	$ 35
[1]Relates primarily to FTR instruments administered by MISO.[2]Relates to commodity trading and is subject to substantial offsetting losses and gains on derivative instruments categorized as levels 1 and 2 in the income statement. See above tables for the income statement impact of derivative activity, including commodity trading gains and losses.[3]NSP-Minnesota nets derivative instruments and related collateral on its consolidated balance sheets when supported by a legally enforceable master netting agreement. At Dec. 31, 2022 and 2021, derivative assets and liabilities include no obligations to return cash collateral. At Dec. 31, 2022 and 2021, derivative assets and liabilities include rights to reclaim cash collateral of $6 million and $16 million, respectively. Counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.[4]NSP-Minnesota currently applies the normal purchase exception to qualifying PPAs. Balance relates to specific contracts that were previously recognized at fair value prior to applying the normal purchase exception, and are being amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.

Fair Value of Long-Term Debt (D

Fair Value of Long-Term Debt (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Financial Liabilities, Balance Sheet Groupings [Abstract]
Long-term Debt, Gross	$ 6,942	$ 6,747
Long-term debt, Fair Value	$ 5,995	$ 7,761

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, 2022	Dec. 31, 2021	Dec. 31, 2020
Defined Benefit Plan Disclosure [Line Items]
annual interest crediting rates	$ 4.86	$ 1.96	$ 1.78
asset transferred	0
Supplemental Executive Retirement Plan (SERP) and Nonqualified Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Total benefit obligation	$ 2,000,000	$ 3,000,000

Benefit Plans and Other Postr_4

Benefit Plans and Other Postretirement Benefits, Pension Benefits (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2023	Dec. 31, 2022		Dec. 31, 2021		Dec. 31, 2020
Supplemental Executive Retirement Plan (SERP) and Nonqualified Pension Plan
Pension Benefits [Abstract]
Total benefit obligation			$ 2		$ 3
Pension Plan
Pension Benefits [Abstract]
Fair value of plan assets			570	[1]	853	[1]	$ 897
Total benefit obligation			657		877		989
Net benefit cost recognized for financial reporting			$ 34		$ 28		$ 32
Expected average long-term rate of return on assets (as a percent)			6.60%		6.60%		7.10%
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (as a percent)			100%		100%
Pension Plan | Domestic and international equity securities
Pension Benefits [Abstract]
Fair value of plan assets	[1]		$ 11		$ 16
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (as a percent)			33%		33%
Pension Plan | Long-duration fixed income and interest rate swap securities
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (as a percent)			38%		37%
Pension Plan | Short-to-intermediate fixed income securities
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (as a percent)			9%		11%
Pension Plan | Alternative investments
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (as a percent)			18%		17%
Pension Plan | Cash
Pension Benefits [Abstract]
Fair value of plan assets	[1]		$ 26		$ 31
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			$ 11		$ 43
Net benefit cost recognized for financial reporting			$ 17		$ 4
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) - Pension Plan - USD ($) $ in Millions		Dec. 31, 2022		Dec. 31, 2021		Dec. 31, 2020
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		$ 570	[1]	$ 853	[1]	$ 897
Plan assets at net asset value	[1]	201		281
Level 1
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	[1]	238		351
Level 2
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	[1]	130		220
Level 3
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	[1]	1		1
Cash
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	[1]	26		31
Plan assets at net asset value	[1]	0		0
Cash | Level 1
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	[1]	26		31
Cash | Level 2
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	[1]	0		0
Cash | Level 3
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	[1]	0		0
Commingled Funds
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	[1]	402		578
Plan assets at net asset value	[1]	201		274
Commingled Funds | Level 1
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	[1]	201		304
Commingled Funds | Level 2
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	[1]	0		0
Commingled Funds | Level 3
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	[1]	0		0
Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	[1]	130		220
Plan assets at net asset value	[1]	0		0
Debt Securities [Member] | Level 1
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	[1]	0		0
Debt Securities [Member] | Level 2
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	[1]	129		219
Debt Securities [Member] | Level 3
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	[1]	1		1
Domestic and international equity securities
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	[1]	11		16
Plan assets at net asset value	[1]	0		0
Domestic and international equity securities | Level 1
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	[1]	11		16
Domestic and international equity securities | Level 2
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	[1]	0		0
Domestic and international equity securities | Level 3
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	[1]	0		0
Other
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	[1]	1		8
Plan assets at net asset value	[1]	0		7
Other | Level 1
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	[1]	0		0
Other | Level 2
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	[1]	1		1
Other | Level 3
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	[1]	$ 0		$ 0
[1]See Note 8 for further information regarding 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) $ in Millions		1 Months Ended		12 Months Ended
		Jan. 31, 2023 USD ($)		Dec. 31, 2022 USD ($) plan		Dec. 31, 2021 USD ($)		Dec. 31, 2020 USD ($)
Cash Flows [Abstract]
Number of pension plans to which contributions were made | plan				4
Components of Net Periodic Benefit Cost (Credit) [Abstract]
Liability, Defined Benefit Plan, Noncurrent				$ (155)		$ (112)
Pension Plan
Change in Projected Benefit Obligation [Roll Forward]
Obligation at Jan. 1		$ 657		877		989
Service cost				27		30		$ 27
Interest cost				25		25		31
Plan amendments				1		1
Actuarial gain				(139)		(28)
Benefit payments				(134)		(140)
Obligation at Dec. 31				657		877		989
Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1		570	[1]	853	[1]	897
Actual return (loss) on plan assets				(154)		62
Employer contributions				5		34
Benefit payments				(134)		(140)
Fair value of plan assets at Dec. 31				570	[1]	853	[1]	897
Funded Status of Plans at Dec. 31 [Abstract]
Funded status				(87)		(24)
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost [Abstract]
Net loss				309		307
Prior service (credit) cost				0		0
Total				309		307
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				12		25
Noncurrent regulatory assets				297		282
Total				$ 309		$ 307
Significant Assumptions Used to Measure Benefit Obligations [Abstract]
Discount rate for year-end valuation (as a percent)				5.80%		3.08%
Expected average long-term increase in compensation level (as a percent)				425%		375%
Components of Net Periodic Benefit Cost (Credit) [Abstract]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement	[2]			$ (38)		$ (35)		$ 0
Defined Benefit Plan, Accumulated Benefit Obligation				600		811
Liability, Defined Benefit Plan, Current				0		0
Liability, Defined Benefit Plan, Noncurrent				(87)		(24)
Defined Benefit Plan, Amounts for Asset (Liability) Recognized in Statement of Financial Position				$ (87)		$ (24)
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate				3.08%		2.71%		3.49%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase				3.75%		3.75%		3.75%
Amounts Not Yet Recognized As Components Of Net Periodic Benefit Cost Recorded As Deferred Income Taxes				$ 0		$ 0
Amounts Not Yet Recognized As Components Of Net Periodic Benefit Cost Recorded As Net-Of-Tax Accumulated Other Comprehensive Income				0		0
Defined Benefit Plan, Accumulated Benefit Obligation				$ (600)		$ (811)
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Rate of Return on Plan Assets				6.60%		6.60%		7.10%
Service cost				$ 27		$ 30		$ 27
Interest cost				25		25		31
Expected return on plan assets				(48)		(52)		(55)
Amortization of prior service cost (credit)				0		0		0
Amortization of net loss				24		34		33
Net periodic pension cost				66		72		36
Effects of regulation				(32)		(44)		(4)
Net benefit cost recognized for financial reporting				34		28		32
Pension Plan | NSP Minnesota [Member]
Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1	[3]			3
Fair value of plan assets at Dec. 31	[3]					3
Cash Flows [Abstract]
Total contributions to Xcel Energy's pension plans during the period				$ 5		$ 34		$ 44
Subsequent Event | Pension Plan | NSP Minnesota [Member]
Cash Flows [Abstract]
Total contributions to Xcel Energy's pension plans during the period		$ 23
[1]See Note 8 for further information regarding fair value measurement inputs and methods.[2]A settlement charge is required when the amount of lump-sum distributions during the year is greater than the sum of the service and interest cost components of the annual net periodic pension cost. In 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 2020.[3]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, 2022	Dec. 31, 2021	Dec. 31, 2020
Postretirement Benefits Plan
Postretirement Health Care Benefits [Abstract]
Total benefit obligation	$ 48	$ 64	$ 73
Defined Benefit Plan, Net Periodic Benefit Cost (Credit)	$ 0	$ 1	$ 0
Target pension asset allocations (as a percent)	100%	100%
Supplemental Executive Retirement Plan (SERP) and Nonqualified Pension Plan
Postretirement Health Care Benefits [Abstract]
Total benefit obligation	$ 2	$ 3
Supplemental Executive Retirement Plan (SERP) and Nonqualified Pension Plan | Parent Company [Member]
Postretirement Health Care Benefits [Abstract]
Total benefit obligation	11	43
Defined Benefit Plan, Net Periodic Benefit Cost (Credit)	$ 17	$ 4
Domestic and international equity securities | Postretirement Benefits Plan
Postretirement Health Care Benefits [Abstract]
Target pension asset allocations (as a percent)	16%	15%
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%
Short-to-intermediate fixed income securities | Postretirement Benefits Plan
Postretirement Health Care Benefits [Abstract]
Target pension asset allocations (as a percent)	71%	71%
Alternative investments | Postretirement Benefits Plan
Postretirement Health Care Benefits [Abstract]
Target pension asset allocations (as a percent)	12%	8%
Cash | Postretirement Benefits Plan
Postretirement Health Care Benefits [Abstract]
Target pension asset allocations (as a percent)	1%	6%

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, 2022		Dec. 31, 2021	Dec. 31, 2020
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		$ 5	[1]	$ 3	$ 2
Plan assets at net asset value	[1]	1		1
Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	[1]	1		0
Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	[1]	3		2
Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	[1]	0		0
Debt Securities [Member]
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	[1]	2		2
Plan assets at net asset value	[1]	0		0
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]	2		1
Plan assets at net asset value	[1]	1		1
Commingled Funds | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	[1]	1		0
Commingled Funds | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	[1]	0		0
Commingled Funds | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	[1]	0		0
Insurance contracts
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		1		0
Plan assets at net asset value		0		0
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		1		0
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, 2022		Dec. 31, 2021		Dec. 31, 2020
Funded Status of Plans at Dec. 31 [Abstract]
Noncurrent liabilities		$ (155,000,000)		$ (112,000,000)
Significant Assumptions Used to Measure Costs [Abstract]
Plan Amendments		0
Pension Plan
Change in Projected Benefit Obligation [Roll Forward]
Obligation at Jan. 1		877,000,000		989,000,000
Service cost		27,000,000		30,000,000		$ 27,000,000
Interest cost		25,000,000		25,000,000		31,000,000
Actuarial gain		(139,000,000)		(28,000,000)
Benefit payments		(134,000,000)		(140,000,000)
Obligation at Dec. 31		657,000,000		877,000,000		989,000,000
Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1		853,000,000	[1]	897,000,000
Actual return (loss) on plan assets		(154,000,000)		62,000,000
Employer contributions		5,000,000		34,000,000
Benefit payments		(134,000,000)		(140,000,000)
Fair value of plan assets at Dec. 31		570,000,000	[1]	853,000,000	[1]	897,000,000
Funded Status of Plans at Dec. 31 [Abstract]
Funded status		(87,000,000)		(24,000,000)
Current liabilities		0		0
Noncurrent liabilities		(87,000,000)		(24,000,000)
Net postretirement amounts recognized on consolidated balance sheets		(87,000,000)		(24,000,000)
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost [Abstract]
Net loss		309,000,000		307,000,000
Prior service (credit) cost		0		0
Total		309,000,000		307,000,000
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		297,000,000		282,000,000
Deferred income taxes		0		0
Net-of-tax accumulated other comprehensive income		0		0
Total		$ 309,000,000		$ 307,000,000
Significant Assumptions Used to Measure Benefit Obligations [Abstract]
Discount rate for year-end valuation (as a percent)		5.80%		3.08%
Components of Net Periodic Benefit Cost (Credit) [Abstract]
Service cost		$ 27,000,000		$ 30,000,000		27,000,000
Interest cost		25,000,000		25,000,000		31,000,000
Expected return on plan assets		(48,000,000)		(52,000,000)		(55,000,000)
Amortization of prior service cost (credit)		0		0		0
Amortization of net loss		24,000,000		34,000,000		33,000,000
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement	[2]	38,000,000		35,000,000		0
Net periodic postretirement benefit cost		66,000,000		72,000,000		36,000,000
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		12,000,000		25,000,000
Defined Benefit Plan Credits (Costs) Not Recognized Due To Effects of Regulation		(32,000,000)		(44,000,000)		(4,000,000)
Net benefit cost recognized for financial reporting		$ 34,000,000		$ 28,000,000		$ 32,000,000
Discount rate (as a percent)		3.08%		2.71%		3.49%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase		3.75%		3.75%		3.75%
Expected average long-term rate of return on assets (as a percent)		6.60%		6.60%		7.10%
Postretirement Benefits Plan
Change in Projected Benefit Obligation [Roll Forward]
Obligation at Jan. 1		$ 64,000,000		$ 73,000,000
Service cost		0		0		$ 0
Interest cost		2,000,000		2,000,000		2,000,000
Actuarial gain		(13,000,000)		(5,000,000)
Benefit payments		(5,000,000)		(6,000,000)
Obligation at Dec. 31		48,000,000		64,000,000		73,000,000
Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1		3,000,000		2,000,000
Actual return (loss) on plan assets		0		0
Employer contributions		7,000,000		7,000,000
Benefit payments		(5,000,000)		(6,000,000)
Fair value of plan assets at Dec. 31		5,000,000	[3]	3,000,000		2,000,000
Funded Status of Plans at Dec. 31 [Abstract]
Funded status		(43,000,000)		(61,000,000)
Current liabilities		(1,000,000)		(3,000,000)
Noncurrent liabilities		(42,000,000)		(58,000,000)
Net postretirement amounts recognized on consolidated balance sheets		(43,000,000)		(61,000,000)
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost [Abstract]
Net loss		16,000,000		31,000,000
Prior service (credit) cost		(1,000,000)		(4,000,000)
Total		15,000,000		27,000,000
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		25,000,000
Deferred income taxes		0		1,000,000
Net-of-tax accumulated other comprehensive income		1,000,000		1,000,000
Total		$ 15,000,000		$ 27,000,000
Significant Assumptions Used to Measure Benefit Obligations [Abstract]
Discount rate for year-end valuation (as a percent)		5.80%		3.09%
Defined Benefit Plan, Health Care Cost Trend Rate Assumed, Pre-65		6.50%		5.30%
Defined Benefit Plan, Health Care Cost Trend Rate Assumed, Post-65		5.50%		4.90%
Ultimate health care trend assumption rate (as a percent)		4.50%		4.50%
Period until ultimate trend rate is reached (in years)		$ 7		$ 4
Components of Net Periodic Benefit Cost (Credit) [Abstract]
Service cost		0		0		0
Interest cost		2,000,000		2,000,000		2,000,000
Expected return on plan assets		0		0		0
Amortization of prior service cost (credit)		(3,000,000)		(3,000,000)		(3,000,000)
Amortization of net loss		1,000,000		2,000,000		1,000,000
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement	[2]	0		0		0
Net periodic postretirement benefit cost		0		1,000,000		0
Significant Assumptions Used to Measure Costs [Abstract]
Plan amendments		0		0
Amounts Not Yet Recognized As Components Of Net Periodic Benefit Cost Recorded As Current Regulatory Assets		0		0
Defined Benefit Plan Credits (Costs) Not Recognized Due To Effects of Regulation		0		0		0
Net benefit cost recognized for financial reporting		$ 0		$ 1,000,000		$ 0
Discount rate (as a percent)		3.09%		2.65%		3.47%
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)		4.10%		4.10%		4.50%
[1]See Note 8 for further information regarding fair value measurement inputs and methods.[2]A settlement charge is required when the amount of lump-sum distributions during the year is greater than the sum of the service and interest cost components of the annual net periodic pension cost. In 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 2020.[3]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, 2023	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Defined Benefit Plan, Net Projected Benefit Payments [Abstract]
Defined Contribution Plan, Administrative Expense			$ 13	$ 13	$ 13
Pension Plan
Defined Benefit Plan, Gross Projected Benefit Payments [Abstract]
2022			84
2023			64
2024			64
2025			61
2026			59
2027-2031			279
Pension Plan | Xcel Energy [Member]
Defined Benefit Plan, Net Projected Benefit Payments [Abstract]
Payment for Pension Benefits			50	131	150
Pension Plan | Xcel Energy [Member] | Subsequent Event
Defined Benefit Plan, Net Projected Benefit Payments [Abstract]
Payment for Pension Benefits	$ 50
Pension Plan | NSP Minnesota [Member]
Defined Benefit Plan, Net Projected Benefit Payments [Abstract]
Payment for Pension Benefits			5	34	44
Pension Plan | NSP Minnesota [Member] | Subsequent Event
Defined Benefit Plan, Net Projected Benefit Payments [Abstract]
Payment for Pension Benefits	$ 23
Postretirement Benefits Plan
Defined Benefit Plan, Gross Projected Benefit Payments [Abstract]
2022			6
2023			5
2024			5
2025			5
2026			4
2027-2031			17
Defined Benefit Plan, Overfunded Plan [Member] | Xcel Energy [Member]
Defined Benefit Plan, Net Projected Benefit Payments [Abstract]
Payment for Pension Benefits			13	15	11
Defined Benefit Plan, Overfunded Plan [Member] | Xcel Energy [Member] | Subsequent Event
Defined Benefit Plan, Net Projected Benefit Payments [Abstract]
Payment for Pension Benefits		$ 12
Defined Benefit Plan, Overfunded Plan [Member] | NSP Minnesota [Member]
Defined Benefit Plan, Net Projected Benefit Payments [Abstract]
Payment for Pension Benefits			$ 7	$ 8	$ 6
Defined Benefit Plan, Overfunded Plan [Member] | NSP Minnesota [Member] | Subsequent Event
Defined Benefit Plan, Net Projected Benefit Payments [Abstract]
Payment for Pension Benefits		$ 6

Commitments and Contingencies S

Commitments and Contingencies Sherco (Details) - USD ($) $ in Millions	1 Months Ended
	Jan. 31, 2021	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

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)	Dec. 31, 2022
Other MGP, Landfill, or Disposal Sites
Loss Contingencies [Line Items]
Number of identified MGP, landfill, or disposal sites under current investigation and/or remediation	5

Commitments and Contingencies E

Commitments and Contingencies Environmental Requirements - Water and Waste (Details) $ in Millions	Dec. 31, 2022 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	$ 40

Commitment and Contingencies AR

Commitment and Contingencies AROs (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2022		Dec. 31, 2021
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance		$ 2,585		$ 2,350
Amounts Incurred		(25)	[1]	(107)	[2]
Accretion		123		116
Cash flow revisions		(6)	[3]	12
Ending balance		2,727		2,585
Fair Value, Measurements, Recurring | Estimate of Fair Value Measurement [Member]
Other Commitments [Line Items]
Legally restricted assets, for purposes of funding future nuclear decommissioning		2,882	[4]	3,256	[5]
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		2,900		3,300
Electric Plant Nuclear Production Decommissioning
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance		2,056		1,957
Amounts Incurred		0	[1]	0	[2]
Accretion		104		99
Cash flow revisions		0	[3]	0
Ending balance		2,160		2,056
Electric Plant Wind Production
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance		384		270
Amounts Incurred		(25)	[1]	(101)	[2]
Accretion		15		13
Cash flow revisions		(8)	[3]	0
Ending balance		416		384
Electric Plant Steam Production Ash Containment
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance		73		67
Amounts Incurred		0	[1]	(6)	[2]
Accretion		2		2
Cash flow revisions		0	[3]	(2)
Ending balance		75		73
Electric Plant Electric Distribution
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance		16		16
Amounts Incurred		0	[1]	0	[2]
Accretion		0		0
Cash flow revisions		0	[3]	0
Ending balance		16		16
Electric Plant Other
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance		0		0
Amounts Incurred	[2]			0
Accretion				0
Cash flow revisions				0
Ending balance				0
Natural Gas Plant Gas Transmission and Distribution
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance		55		39
Amounts Incurred		0	[1]	0	[2]
Accretion		2		2
Cash flow revisions		2	[3]	14
Ending balance		59		55
Common and Other Property Common Miscellaneous
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance		1		1
Amounts Incurred		0	[1]	0	[2]
Accretion		0		0
Cash flow revisions		0	[3]	0
Ending balance		$ 1		$ 1
[1]Amounts incurred relate to the wind farms placed in service in 2022 (Dakota Range and Rock Aetna).[2]relate to the wind farms placed in service in 2021 (Blazing Star 2, Mower and Freeborn) and removal of a utility scale battery asset.[3]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.[4]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.[5]Reported in nuclear decommissioning fund and other investments on the consolidated balance sheets, which also includes $52 million of rabbi trust assets and other miscellaneous investments.

Indeterminate AROs (Details)

Indeterminate AROs (Details) $ in Millions	Dec. 31, 2022 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, 2022 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	13,200
Maximum assessments per reactor per accident	$ 138
Number of owned and licensed reactors | Reactor	3
Maximum funding requirement per reactor for any one year	$ 20
Number of nuclear plant sites operated by NSP-Minnesota | Plant	2
Maximum assessments for business interruption insurance each calendar year	$ 12
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	13,700
Insurance coverage limits for NSP-Minnesota's nuclear plant sites	2,800
Business Interruption Insurance Coverage Provided by NEIL	$ 350

Commitments and Contingencies N

Commitments and Contingencies Nuclear Fuel Disposal (Details) $ in Millions	Dec. 31, 2022 USD ($) Canister		Dec. 31, 2021 USD ($)
Estimate of Fair Value Measurement [Member] | Fair Value, Measurements, Recurring
Loss Contingencies [Line Items]
Decommissioning Fund Investments | $	$ 2,882	[1]	$ 3,256	[2]
Estimate of Fair Value Measurement [Member] | Fair Value, Measurements, Recurring | Nuclear Decommissioning Fund [Member]
Loss Contingencies [Line Items]
Decommissioning Fund Investments | $	$ 2,900		3,300
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 | Nuclear Decommissioning Fund [Member]
Loss Contingencies [Line Items]
Decommissioning Fund Investments | $	$ 2,900		$ 3,300
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 $48 million of rabbi trust assets and other miscellaneous investments.[2]Reported in nuclear decommissioning fund and other investments on the consolidated balance sheets, which also includes $52 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, 2022		Dec. 31, 2021		Dec. 31, 2020
Public Utilities, General Disclosures [Line Items]
Asset Retirement Obligation	$ 2,727		$ 2,585		$ 2,350
Nuclear Plant [Member]
Public Utilities, General Disclosures [Line Items]
Asset Retirement Obligation	2,160		2,056		$ 1,957
Fair Value Measured on a Recurring Basis | Estimate of Fair Value Measurement [Member]
Public Utilities, General Disclosures [Line Items]
Decommissioning Fund Investments	2,882	[1]	3,256	[2]
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	$ 2,900		$ 3,300
[1]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.[2]Reported in nuclear decommissioning fund and other investments on the consolidated balance sheets, which also includes $52 million of rabbi trust assets and other miscellaneous investments.

Commitments and Contingencies_3

Commitments and Contingencies, Leases (Details) - USD ($)		12 Months Ended
		Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Lessee, Lease, Description [Line Items]
Maximum Length - Short-Term Leases		12 months
Short-term Lease, Cost		$ 3,000,000	$ 2,000,000	$ 2,000,000
Operating Lease, Weighted Average Discount Rate, Percent		3.80%
Operating Lease, Assets and Liabilities, Lessee [Abstract]
Operating Lease, Right-of-Use Asset, Gross		$ 634,000,000	630,000,000
Operating Lease, Right-of-Use Asset, Accumulated Depreciation		(310,000,000)	(222,000,000)
Operating lease right-of-use assets		324,000,000	408,000,000
Lease, Cost [Abstract]
Operating Lease, Cost	[1]	107,000,000	104,000,000	97,000,000
Lessee, Operating Lease, Liability, Payment, Due [Abstract]
2023		110,000,000
2024		107,000,000
2025		87,000,000
2026		47,000,000
2027		7,000,000
Thereafter		24,000,000
Total minimum obligation		382,000,000
Interest component of obligation		(28,000,000)
Present value of minimum obligation		354,000,000
Less current portion		(98,000,000)	(90,000,000)
Operating lease liabilities		256,000,000	353,000,000
Weighted Average Remaining lease term, operating		7.6
Property, Plant and Equipment, Other Types [Member]
Operating Lease, Assets and Liabilities, Lessee [Abstract]
Operating Lease, Right-of-Use Asset, Gross		78,000,000	74,000,000
Lease, Cost [Abstract]
Operating Lease, Cost	[2]	9,000,000	8,000,000	8,000,000
Lessee, Operating Lease, Liability, Payment, Due [Abstract]
2023		12,000,000
2024		7,000,000
2025		8,000,000
2026		7,000,000
2027		7,000,000
Thereafter		24,000,000
Total minimum obligation		65,000,000
Interest component of obligation		(9,000,000)
Present value of minimum obligation		56,000,000
Purchased Power Agreements
Operating Lease, Assets and Liabilities, Lessee [Abstract]
Operating Lease, Right-of-Use Asset, Gross		556,000,000	556,000,000
Lease, Cost [Abstract]
Operating Lease, Cost		98,000,000	$ 96,000,000	$ 89,000,000
Lessee, Operating Lease, Liability, Payment, Due [Abstract]
2023	[3],[4]	98,000,000
2024	[3],[4]	100,000,000
2025	[3],[4]	79,000,000
2026	[3],[4]	40,000,000
2027	[3],[4]	0
Thereafter	[3],[4]	0
Total minimum obligation	[3],[4]	317,000,000
Interest component of obligation	[3],[4]	(19,000,000)
Present value of minimum obligation	[3],[4]	$ 298,000,000
[1]PPA capacity payments are included in electric fuel and purchased power on the consolidated statements of income. Expense for other operating leases is included in O&M expense and electric fuel and purchased power.[2] Includes short-term lease expense o f $3 million, $2 million and $2 million for 2022, 2021 and 2020, respectively.

Commitments and Contingencies_4

Commitments and Contingencies, Purchased Power Agreements (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Energy
Purchased Power Agreements (PPAs) [Abstract]
Purchased power expense		$ 182	$ 149	$ 112
Estimated Future Payments Under PPAs [Abstract]
2023	[1]	50
2024	[1]	45
2025	[1]	51
2026	[1]	48
2027	[1]	55
Thereafter	[1]	28
Total	[1],[2]	277
Capacity
Purchased Power Agreements (PPAs) [Abstract]
Purchased power expense		60	$ 55	$ 52
Estimated Future Payments Under PPAs [Abstract]
2023		61
2024		63
2025		26
2026		9
2027		7
Thereafter		3
Total	[2]	$ 169
[1]Excludes contingent energy payments for renewable energy PPAs.[2]Includes amounts allocated to NSP-Wisconsin through intercompany charges.

Commitments and Contingencies_5

Commitments and Contingencies, Fuel Contracts (Details) $ in Millions	Dec. 31, 2022 USD ($)
Coal
Fuel Contracts [Abstract]
2023	$ 227
2024	110
2025	17
2026	1
2027	1
Thereafter	0
Total	356	[1]
Nuclear Fuel
Fuel Contracts [Abstract]
2023	144
2024	112
2025	158
2026	37
2027	155
Thereafter	194
Total	800	[1]
Natural Gas Supply
Fuel Contracts [Abstract]
2023	130
2024	1
2025	1
2026	0
2027	0
Thereafter	0
Total	132	[1]
Natural Gas Storage and Transportation
Fuel Contracts [Abstract]
2023	158
2024	148
2025	138
2026	143
2027	98
Thereafter	116
Total	$ 801	[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, 2022	Dec. 31, 2021
Equity Method Investment, Nonconsolidated Investee or Group of Investees [Member]
Purchased Power Agreements [Abstract]
Generating capacity (in MW)	1,347	1,347

Other Comprehensive Income (Det

Other Comprehensive Income (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021		Dec. 31, 2020
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Accumulated other comprehensive loss at Jan. 1	$ 7,573
Accumulated other comprehensive (loss) income at end of period	7,836	$ 7,573
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Tax	0	0		$ 0
Gains and Losses on Cash Flow Hedges
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Accumulated other comprehensive loss at Jan. 1	(17)	(19)
Net current period other comprehensive income	1	2
Accumulated other comprehensive (loss) income at end of period	(16)	(17)		(19)
Other comprehensive income (loss) before reclassifications	0
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)	(2)	[1]
Defined Benefit Pension and Postretirement Items
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Accumulated other comprehensive loss at Jan. 1	(3)	(3)
Net current period other comprehensive income	1	0
Accumulated other comprehensive (loss) income at end of period	(2)	(3)		(3)
Other comprehensive income (loss) before reclassifications	1
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	(20)	(22)
Net current period other comprehensive income	2	2
Accumulated other comprehensive (loss) income at end of period	(18)	(20)		$ (22)
Other comprehensive income (loss) before reclassifications	1
Total | Interest Rate Swap [Member]
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Amortization of interest rate hedges	$ (1)	$ (2)
[1]Included in interest charges.

Segments and Related Informat_3

Segments and Related Information (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Segment Reporting Information [Line Items]
Natural gas		$ 1,022	$ 623	$ 493
Other		45	39	37
Total operating revenues		6,684	5,756	5,101
Depreciation and amortization		1,014	926	825
Total interest charges and financing costs		279	258	238
Income tax benefit		(112)	(48)	(6)
Net income (loss)		675	606	591
Related Party Transaction - Electric Domestic Regulated Revenue		514	501	440
Related Party Transaction - Gas Domestic Regulated Revenue		0	1	1
Regulated Electricity
Segment Reporting Information [Line Items]
Revenues Including Intersegment Revenues		5,618	5,095	4,572
Depreciation and amortization		953	869	773
Total interest charges and financing costs		257	240	221
Income tax benefit		(127)	(53)	(14)
Net income (loss)		626	566	553
Regulated Natural Gas
Segment Reporting Information [Line Items]
Revenues Including Intersegment Revenues		1,024	624	493
Depreciation and amortization		60	56	51
Total interest charges and financing costs		22	18	17
Income tax benefit		14	6	7
Net income (loss)		45	29	30
All Other
Segment Reporting Information [Line Items]
Depreciation and amortization		1	1	1
Income tax benefit		1	(1)	1
Net income (loss)		4	11	8
Total revenues
Segment Reporting Information [Line Items]
Total operating revenues	[1],[2]	6,687	5,758	5,102
Total revenues | Regulated Electricity
Segment Reporting Information [Line Items]
Operating revenue, Regulated Electric	[2]	5,617	5,094	4,571
Total revenues | Regulated Natural Gas
Segment Reporting Information [Line Items]
Natural gas	[1]	1,022	623	493
Total revenues | All Other
Segment Reporting Information [Line Items]
Other		45	39	37
Intersegment Eliminations
Segment Reporting Information [Line Items]
Total operating revenues		(3)	(2)	(1)
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	$ 1	$ 0
[1]Operating revenues include $0 million, $1 million and $1 million of affiliate gas revenue for the years ended Dec. 31, 2022, 2021 and 2020, respectively. See Note 13 for further information.[2]Operating revenues include $514 million, $501 million and $440 million of affiliate electric revenue for the years ended Dec. 31, 2022, 2021 and 2020, respectively. See Note 13 for further information.

Related Party Transactions (Det

Related Party Transactions (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Revenues [Abstract]
Operating Revenue from Related Parties		$ 0	$ 0
Operating expenses
Interest Income, Related Party	$ 1
Interest expense	1	0	0
Accounts Receivable and Payable with Affiliates [Abstract]
Accounts receivable	45	29
Accounts payable	89	63
NSP-Wisconsin
Accounts Receivable and Payable with Affiliates [Abstract]
Accounts receivable	4	13
Accounts payable	0	0
PSCo
Accounts Receivable and Payable with Affiliates [Abstract]
Accounts receivable	0	16
Accounts payable	2	0
SPS
Accounts Receivable and Payable with Affiliates [Abstract]
Accounts receivable	0	0
Accounts payable	3	2
Other subsidiaries of Xcel Energy Inc.
Accounts Receivable and Payable with Affiliates [Abstract]
Accounts receivable	41	0
Accounts payable	84	61
Purchased Power
Operating expenses
Costs and Expenses, Related Party	70	67	59
Transmission Expense
Operating expenses
Costs and Expenses, Related Party	132	121	109
Other Expense
Operating expenses
Costs and Expenses, Related Party	673	615	584
Electricity, US Regulated
Revenues [Abstract]
Operating Revenue from Related Parties	514	501	440
Natural Gas, US Regulated
Revenues [Abstract]
Operating Revenue from Related Parties	$ 0	$ 1	$ 1

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, 2022	Dec. 31, 2021	Dec. 31, 2020
SEC Schedule, 12-09, Movement in Valuation Allowances and Reserves [Roll Forward]
Balance at Jan. 1		$ 45	$ 33	$ 23
Charged to costs and expenses		21	24	24
Charged to other accounts	[1]	6	5	5
Deductions from reserves	[2]	(26)	(17)	(19)
Balance at Dec. 31		$ 46	$ 45	$ 33
[1]Recovery of amounts previously written-off.[2]Deductions related primarily to bad debt write-offs.