Northern States Power 10-K 23 Feb 22 2021 FY Annual report Financial data

Cover Page

Cover Page - USD ($)	12 Months Ended
	Dec. 31, 2021	Feb. 23, 2022	Jun. 30, 2021
Cover [Abstract]
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2021
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	2021
Document Fiscal Period Focus	FY
Amendment Flag	false
Entity Public Float			$ 0

Audit Information

Audit Information	12 Months Ended
	Dec. 31, 2021
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, 2021	Dec. 31, 2020	Dec. 31, 2019
Operating revenues
Electric, non-affiliates	$ 4,593	$ 4,131	$ 4,049
Electric, affiliates	501	440	457
Natural gas	623	493	571
Other	39	37	35
Total operating revenues	5,756	5,101	5,112
Operating expenses
Electric fuel and purchased power	2,042	1,626	1,601
Cost of natural gas sold and transported	385	263	327
Cost of sales — other	23	22	23
Operating and maintenance expenses	1,190	1,191	1,203
Conservation program expenses	144	119	120
Depreciation and amortization	926	825	791
Taxes (other than income taxes)	264	259	260
Total operating expenses	4,974	4,305	4,325
Operating income	782	796	787
Other income (expense), net	4	2	(1)
Allowance for funds used during construction — equity	30	25	25
Interest charges and financing costs
Interest charges — includes other financing costs of $8, $8 and $7, respectively	271	249	233
Allowance for funds used during construction — debt	(13)	(11)	(12)
Total interest charges and financing costs	258	238	221
Income before income taxes	558	585	590
Income tax (benefit) expense	(48)	(6)	47
Net income	$ 606	$ 591	$ 543

CONSOLIDATED STATEMENTS OF IN_2

CONSOLIDATED STATEMENTS OF INCOME (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Income Statement [Abstract]
Other financing costs	$ 8	$ 8	$ 7

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Comprehensive income:
Net income	$ 606	$ 591	$ 543
Derivative instruments:
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax	2	1	0
Total other comprehensive income	2	1	0
Total comprehensive income	$ 608	$ 592	$ 543

CONSOLIDATED STATEMENTS OF CO_2

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
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, 2021	Dec. 31, 2020	Dec. 31, 2019
Operating activities
Net income	$ 606	$ 591	$ 543
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	932	831	798
Nuclear fuel amortization	114	123	119
Deferred income taxes	(36)	(67)	(39)
Allowance for equity funds used during construction	(30)	(25)	(25)
Provision for bad debts	24	24	13
Changes in operating assets and liabilities:
Accounts receivable	(89)	(55)	15
Accrued unbilled revenues	(71)	1	20
Inventories	(22)	(14)	(29)
Other current assets	3	(9)	(3)
Accounts payable	69	(1)	(13)
Net regulatory assets and liabilities	(282)	(87)	(140)
Other current liabilities	(5)	(58)	(12)
Pension and other employee benefit obligations	(41)	(54)	(49)
Other, net	(50)	(8)	(29)
Net cash provided by operating activities	1,122	1,192	1,169
Investing activities
Capital/construction expenditures	(1,866)	(1,901)	(1,417)
Purchase of investment securities	(757)	(1,398)	(995)
Proceeds from the sale of investment securities	743	1,378	975
Investments in utility money pool arrangement	(821)	(718)	(219)
Repayments from utility money pool arrangement	730	718	219
Other, net	1	1	(3)
Net cash used in investing activities	(1,970)	(1,920)	(1,440)
Financing activities
(Repayments of) proceeds from short-term borrowings, net	(179)	149	(120)
Borrowings under utility money pool arrangement	434	136	696
Repayments under utility money pool arrangement	(434)	(136)	(696)
Proceeds from issuance of long-term debt	836	677	580
Repayment of long-term debt	0	(300)	0
Capital contributions from parent	649	527	354
Dividends paid to parent	(431)	(408)	(467)
Other, net	0	3	0
Net cash provided by financing activities	875	648	347
Net change in cash, cash equivalents and restricted cash	27	(80)	76
Cash, cash equivalents and restricted cash at beginning of period	46	126	50
Cash, cash equivalents and restricted cash at end of period	73	46	126
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	(245)	(230)	(209)
Cash received (paid) for income taxes, net	11	(53)	(105)
Supplemental disclosure of non-cash investing and financing transactions:
Accrued property, plant and equipment additions	242	74	95
Inventory transfers to property, plant and equipment	8	24	24
Operating lease right-of-use assets	4	2	629
Allowance for equity funds used during construction	$ 30	$ 25	$ 25

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions		Dec. 31, 2021	Dec. 31, 2020
Current assets
Cash and cash equivalents		$ 73
Accounts receivable, net		429	$ 392
Accounts receivable from affiliates		29	32
Investments in money pool arrangements		91	0
Accrued unbilled revenues		319	248
Inventories		309	295
Regulatory assets		527	411
Derivative instruments		53	17
Prepayments and other		46	50
Total current assets		1,876	1,491
Property, plant and equipment, net		16,430	15,308
Other assets
Nuclear decommissioning fund and other investments		3,308	2,830
Regulatory assets		718	924
Derivative instruments		33	5
Operating lease right-of-use assets		408	488
Other		36	14
Total other assets		4,503	4,261
Total assets		22,809	21,060
Current liabilities
Current portion of long-term debt		300	0
Short-term debt		0	179
Accounts payable		522	438
Accounts payable to affiliates		63	66
Regulatory liabilities	[1]	117	123
Taxes accrued		260	263
Accrued interest		78	72
Dividends payable to parent		96	106
Derivative instruments		35	22
Operating lease liabilities		90	85
Other		166	154
Total current liabilities		1,727	1,508
Deferred credits and other liabilities
Deferred income taxes		1,949	1,840
Deferred investment tax credits		17	18
Regulatory liabilities	[1]	1,927	1,896
Asset retirement obligations		2,585	2,350
Derivative instruments		71	71
Pension and employee benefit obligations		112	192
Operating lease liabilities		353	443
Other		48	69
Total deferred credits and other liabilities		7,062	6,879
Commitments and contingencies
Capitalization
Long-term debt		6,447	5,904
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		$ 5,202	$ 4,585
Retained earnings		2,391	2,206
Accumulated other comprehensive loss		(20)	(22)
Total common stockholder's equity		7,573	6,769
Total liabilities and equity		$ 22,809	$ 21,060
[1]	Revenue subject to refund of $15 million and $17 million for 2021 and 2020, 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, 2018		1,000,000
Balance at beginning of period at Dec. 31, 2018	$ 5,573	$ 0	$ 3,624	$ 1,972	$ (23)
Increase (Decrease) in Stockholder's Equity
Net income	543			543
Other comprehensive income	0
Dividends declared to parent	(479)			(479)
Contribution of capital by parent	444		444
Balance at end of period (shares) at Dec. 31, 2019		1,000,000
Balance at end 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	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)

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2021
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 in 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 the 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, 2021 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 of recovering deferred costs and returning deferred credits are based on specific ratemaking decisions or precedent for each item. 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 from its balance sheet. 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 financial statements. NSP-Minnesota defers income taxes 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 NSP-Minnesota’s tax rate changes are generally subject to a normalization method of accounting. Therefore, the revaluation of most of its net deferred taxes upon a tax rate reduction results in the establishment of a net regulatory liability, which would be refundable to utility customers over the remaining life of the related assets. NSP-Minnesota anticipates that a tax rate increase would 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 it over the book depreciable lives of the related property. The requirement to defer and amortize tax credits only applies to federal ITCs related to public utility property. Utility rate regulation also has resulted in the recognition of regulatory assets and liabilities related to income taxes. 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. NSP-Minnesota follows the applicable accounting guidance to measure and disclose uncertain tax positions that it has taken or expects to take in its income tax returns. NSP-Minnesota recognizes a tax position in its 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. NSP-Minnesota reports interest and penalties related to income taxes 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. Planned maintenance activities are charged to operating expense unless the cost represents the acquisition of an additional unit of property or the replacement of an existing unit of property. 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. NSP-Minnesota records depreciation expense 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 recovered in rates as authorized by the appropriate regulatory entities. The amount of removal costs is based on current factors used in existing depreciation rates. Accumulated removal costs are reflected in the consolidated balance sheet as a regulatory liability. Depreciation expense, expressed as a percentage of average depreciable property, was approximately 3.7% for 2021, 3.7% for 2020 and 3.7% for 2019. See Note 3 for further information. AROs — NSP-Minnesota accounts for AROs under accounting guidance that requires a liability for the fair value of an ARO to be recognized in the period in which it is incurred if it can be reasonably estimated, with the offsetting associated asset retirement 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 depreciated over the useful life of the long-lived asset. Changes resulting from revisions to the timing or amount 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 performed at least every three years and submitted to the state commissions for approval. 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 liability can be reasonably estimated. Costs are deferred as a regulatory asset if it is probable that 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 proceeds. 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. NSP-Minnesota does not recognize a separate financing component of its collections from customers as contract terms are short-term in nature. NSP-Minnesota presents its revenues net of any excise or sales taxes or fees. NSP-Minnesota recognizes physical sales to customers (native load and wholesale) on a gross basis in electric revenues and cost of sales. Revenues and charges for short-term physical wholesale sales of excess energy transacted through RTOs are also recorded on a gross basis. Other revenues and charges settled/facilitated through an RTO are recorded on a net basis in cost of sales. NSP-Minnesota has various rate-adjustment mechanisms that provide for the recovery of natural gas, electric fuel and purchased energy costs. Cost-adjustment tariffs may increase or decrease the level of revenue collected from customers and are revised periodically for differences between the total amount collected under the clauses and the costs incurred. When applicable, fuel cost over-recoveries (the excess of fuel revenue billed to customers over fuel costs incurred) are deferred as regulatory liabilities and under-recoveries (the excess of fuel costs incurred over fuel revenues billed to customers) are deferred as regulatory assets. See Note 6 for further information. Cash and Cash Equivalents — NSP-Minnesota considers investments in instruments with a remaining maturity of three months or less at the time of purchase to be cash equivalents. Accounts Receivable and Allowance for Bad Debts — Accounts receivable are stated at the actual billed amount net of an allowance for bad debts. NSP-Minnesota establishes an allowance for uncollectible receivables based on a policy that reflects its expected exposure to the credit risk of customers. As of Dec. 31, 2021 and 2020, the allowance for bad debts wa s $45 million and $33 million, respectively. Inventory — Inventory is recorded at average cost and consisted of the following: (Millions of Dollars) Dec. 31, 2021 Dec. 31, 2020 Inventories Materials and supplies $ 181 $ 178 Fuel 81 90 Natural gas 47 27 Total inventories $ 309 $ 295 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. Cash equivalents are recorded at cost plus accrued interest; money market funds are measured using quoted NAVs. For interest rate derivatives, quoted prices based primarily on observable market interest rate curves are used to establish 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, NSP-Minnesota may use quoted prices for similar contracts or internally prepared valuation models 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 estimate fair value for each security. See Notes 8 and 9 for further information. Derivative Instruments — NSP-Minnesota uses derivative instruments in connection with its interest rate, utility commodity price and commodity trading activities, 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 and interest rate hedging transactions are recorded as a component of interest expense. 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 a derivative exists and/or whether an instrument may be exempted from derivative accounting if designated as a normal purchase or normal sale. 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. AFUDC 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 for establishing utility rates. Alternative Revenue — Certain rate rider mechanisms (including decoupling/sales true up and CIP/DSM programs) qualify as alternative revenue programs. These mechanisms arise from costs imposed upon the utility by action of a regulator or legislative body related to an environmental, public safety or other mandate or from other instances where 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 equal to the revenue requirement, which may include incentives and return on rate base items. Billing amounts are revised periodically for differences between total amount collected and revenue earned, which may increase or decrease the level of revenue collected from customers. Alternative revenues arising from these programs are presented on a gross basis and disclosed separately from revenue from contracts with customers. See Note 6 for further information. Conservation Programs — Costs incurred for DSM and CIP programs are deferred if it is probable future revenue will recover the incurred cost. Revenues recognized for incentive programs for the recovery of lost margins and/or conservation performance incentives are limited to amounts expected to be collected within 24 months from the year they are earned. Regulatory assets are recognized to reflect the amount of costs or earned incentives that have not yet been collected from customers. Emission Allowances — Emission allowances are recorded at cost, including broker commission fees. The inventory accounting model is utilized for all emission allowances and 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. 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.

Accounting Pronouncements

Accounting Pronouncements	12 Months Ended
	Dec. 31, 2021
Accounting Standards Update and Change in Accounting Principle [Abstract]
Accounting Pronouncements	Recently Adopted Credit Losses — In 2016, the FASB issued Financial Instruments - Credit Losses, Topic 326 (ASC Topic 326), which changes how entities account for losses on receivables and certain other assets. The guidance requires use of a current expected credit loss model, which may result in earlier recognition of credit losses than under previous accounting standards. NSP-Minnesota implemented the guidance using a modified-retrospective approach, recognizing a cumulative effect charge o f $1 million (aft

Property Plant and Equipment Pr

Property Plant and Equipment Property Plant and Equipment	12 Months Ended
	Dec. 31, 2021
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment Disclosure	Major classes of property, plant and equipment (Millions of Dollars) Dec. 31, 2021 Dec. 31, 2020 Property, plant and equipment, net Electric plant $ 19,154 $ 18,948 Natural gas plant 1,864 1,707 Common and other property 1,007 955 Plant to be retired (a) 719 136 CWIP 984 1,150 Total property, plant and equipment 23,728 22,896 Less accumulated depreciation (7,606) (7,898) Nuclear fuel 3,081 2,970 Less accumulated amortization (2,773) (2,660) Property, plant and equipment, net $ 16,430 $ 15,308 (a) Includes regulator-approved retirements of Sherco Units 1, 2 and 3 and A.S. King. Joint Ownership of Generation and Transmission Facilities Jointly owned assets as of Dec. 31, 2021: (Millions of Dollars, Except Percent Owned) Plant in Service Accumulated Depreciation Percent Owned Electric generation: Sherco Unit 3 $ 620 $ 451 59 % Sherco common facilities 178 108 80 Sherco substation 5 4 59 Electric transmission: Grand Meadow 11 3 50 Huntley Wilmarth 48 1 50 CapX2020 952 127 51 Total (a) $ 1,814 $ 694 (a) Projects additionally include $7 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, 2021
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, 2021 Dec. 31, 2020 Regulatory Assets Current Noncurrent Current Noncurrent Pension and retiree medical obligations 9 Various $ 24 $ 301 $ 26 $ 364 Deferred natural gas and electric energy/fuel costs One five 138 190 8 18 Recoverable deferred taxes on AFUDC Plant lives — 114 — 113 Excess deferred taxes — TCJA 7 Various 10 113 10 122 Sales true-up and revenue decoupling One two 33 56 101 28 Benson biomass PPA termination and asset purchase Eight 10 55 10 65 PI extended power uprate 13 years 4 46 3 49 Contract valuation adjustments (a) 1, 8 Term of related contract 18 34 16 48 Purchased power contracts costs Term of related contract 6 27 4 32 Conservation programs (b) 1 One two 7 22 14 23 Laurentian biomass PPA termination Two 18 18 18 36 Nuclear refueling outage costs 1 One two 37 16 28 10 Losses on reacquired debt Term of related debt 1 11 1 12 Environmental remediation costs 1, 10 Pending future rate cases — 5 1 9 Renewable resources and environmental initiatives One two 170 3 129 1 State commission adjustments Plant lives — 3 — 3 Gas pipeline inspection and remediation costs One two 33 — 26 — Net AROs (c) 1, 10 Various — (316) — (32) Other Various 18 20 16 23 Total regulatory assets $ 527 $ 718 $ 411 $ 924 (a) Includes the fair value of certain long-term PPAs used to meet energy capacity requirements and valuation adjustments on natural gas commodity purchases. (b) Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions. (c) Includes amounts recorded for future recovery of AROs, less amounts recovered through nuclear decommissioning accruals and gains from decommissioning investments. Components of regulatory liabilities: (Millions of Dollars) See Note(s) Remaining Amortization Period Dec. 31, 2021 Dec. 31, 2020 Regulatory Liabilities Current Noncurrent Current Noncurrent Deferred income tax adjustments and TCJA refunds (a) 7 Various $ 9 $ 1,256 $ 9 $ 1,326 Plant removal costs 1, 10 Various — 613 — 544 Renewable resources and environmental initiatives Various 1 10 5 — ITC deferrals 1 Various — 7 — 8 Contract valuation adjustments (b) 1, 8 Less than one year 29 — 12 — DOE Settlement Less than one year 14 — 11 — Deferred natural gas and electric energy/fuel costs Less than one year 14 — 8 — Other Various 50 41 78 18 Total regulatory liabilities (c) $ 117 $ 1,927 $ 123 $ 1,896 (a) Includes the revaluation of recoverable/regulated plant accumulated deferred income taxes and revaluation impact of non-plant accumulated deferred income taxes due to the TCJA. (b) Includes the fair value of certain long-term PPAs used to meet energy capacity requirements and valuation adjustments on natural gas commodity purchases. (c) Revenue subject to refund of $15 million and $17 million for 2021 and 2020, respectively, is included in other current liabilities. At Dec. 31, 2021 and 2020, NSP-Minnesota’s regulatory assets not earning a return primarily included the unfunded portion of pension and retiree medical obligations and net AROs. In addition, regulatory assets included $691 million and $399 million at Dec. 31, 2021 and 2020, respectively, of past expenditures not earning a return. Amounts are related to funded pension obligations, sales true-up and revenue decoupling, purchased natural gas and electric energy costs (including those related to Winter Storm Uri), various renewable resources and certain environmental initiatives.

Borrowings and Other Financing

Borrowings and Other Financing Instruments	12 Months Ended
	Dec. 31, 2021
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, 2021 Year Ended Dec. 31 2021 2020 2019 Borrowing limit $ 250 $ 250 $ 250 $ 250 Amount outstanding at period end — — — — Average amount outstanding — 6 3 32 Maximum amount outstanding — 236 116 250 Weighted average interest rate, computed on a daily basis N/A 0.07 % 1.53 % 2.05 % 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, 2021 Year Ended Dec. 31 2021 2020 2019 Borrowing limit $ 500 $ 500 $ 500 $ 500 Amount outstanding at period end — — 179 30 Average amount outstanding — 26 10 71 Maximum amount outstanding 13 317 179 317 Weighted average interest rate, computed on a daily basis 0.15 % 0.18 % 1.25 % 2.59 % Weighted average interest rate at end of period N/A N/A 0.18 2.05 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, 2021 and 2020, there were $9 million and $10 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) 2021 2020 47 % 47 % $ 100 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, 2021, 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, 2021 (in millions of dollars): Credit Facility (a) Drawn (b) Available $ 500 $ 9 $ 491 (a) This credit facility matures in June 2024. (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, 2021 and 2020. Bilateral Credit Agreement — In April 2021, 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, 2021, NSP-Minnesota had $45 million outstanding letters of credit under the $75 million Bilateral Credit Agreement. Long-Term Borrowings and Other Financing Instruments Generally, all property of NSP-Minnesota is subject to the lien of its first mortgage indenture. 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 2021 2020 First mortgage bonds 2.15 % Aug. 15, 2022 $ 300 $ 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 — 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 (b) 2.60 June 1, 2051 700 700 First mortgage bonds (a) 3.20 April 1, 2052 425 — Other long-term debt 3 — Unamortized discount (44) (42) Unamortized debt issuance cost (62) (54) Current maturities (300) — Total long-term debt $ 6,447 $ 5,904 (a) 2021 financing. (b) 2020 financing. Maturities of long-term debt are as follows: (Millions of Dollars) 2022 $ 300 2023 400 2024 — 2025 250 2026 — Deferred Financing Costs — Deferred financing costs of approximately $62 million and $54 million, net of amortization, are presented as a deduction from the carrying amount of long-term debt at Dec. 31, 2021 and 2020, 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, 2021: Equity to Total Equity to Total Capitalization Ratio Actual Low High 2021 47.2 % 57.6 % 52.9 % Unrestricted Retained Earnings Total Capitalization Limit on Total Capitalization $ 1,558 million $ 14,321 million $ 15,332 million

Revenues

Revenues	12 Months Ended
	Dec. 31, 2021
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, 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 Year Ended Dec. 31, 2019 (Millions of Dollars) Electric Natural Gas All Other Total Major revenue types Revenue from contracts with customers: Residential $ 1,280 $ 303 $ 30 $ 1,613 C&I 2,054 229 — 2,283 Other 33 — 5 38 Total retail 3,367 532 35 3,934 Wholesale 210 — — 210 Transmission 216 — — 216 Interchange 459 — — 459 Other 12 9 — 21 Total revenue from contracts with customers 4,264 541 35 4,840 Alternative revenue and other 242 30 — 272 Total revenues $ 4,506 $ 571 $ 35 $ 5,112

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2021
Income Tax Disclosure [Abstract]
Income Taxes	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. 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 December 2022 2018 September 2022 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, 2021, NSP-Minnesota’s earliest open tax year subject to examination by state taxing authorities under applicable statutes of limitations is 2014. In July 2020, Minnesota began an audit of tax years 2015 - 2018. As of Dec. 31, 2021, no material adjustments have been proposed. 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, 2021 Dec. 31, 2020 Unrecognized tax benefit — Permanent tax positions $ 23 $ 21 Unrecognized tax benefit — Temporary tax positions 3 3 Total unrecognized tax benefit $ 26 $ 24 Changes in unrecognized tax benefits: (Millions of Dollars) 2021 2020 2019 Balance at Jan. 1 $ 24 $ 20 $ 17 Additions based on tax positions related to the current year 2 2 3 Reductions based on tax positions related to the current year — — (1) Additions for tax positions of prior years — 16 1 Reductions for tax positions of prior years — (14) — Balance at Dec. 31 $ 26 $ 24 $ 20 Unrecognized tax benefits were reduced by tax benefits associated with NOL and tax credit carryforwards: (Millions of Dollars) Dec. 31, 2021 Dec. 31, 2020 NOL and tax credit carryforwards $ (13) $ (11) 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 $14 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) 2021 2020 2019 Payable for interest related to unrecognized tax benefits at Jan. 1 $ (2) $ (2) $ (1) Interest expense related to unrecognized tax benefits — — (1) Payable for interest related to unrecognized tax benefits at Dec. 31 $ (2) $ (2) $ (2) No amounts were accrued for penalties related to unrecognized tax benefits as of Dec. 31, 2021, 2020 or 2019. 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) 2021 2020 Federal NOL carryforward $ 77 $ — Federal tax credit carryforwards 704 543 State NOL carryforwards 344 151 Valuation allowances for state NOL carryforwards (1) (1) State tax credit carryforwards, net of federal detriment (a) 78 71 Valuation allowances for state credit carryforwards, net of federal benefit (b) (64) (59) (a) State tax credit carryforwards are net of federal detriment of $21 million and $19 million as of Dec. 31, 2021 and 2020, respectively. (b) Valuation allowances for state tax credit carryforwards were net of federal benefit of $17 million and $16 million as of Dec. 31, 2021 and 2020, respectively. Federal carryforward periods expire between 2031 and 2041 and state carryforward periods expire starting 2022. Total income tax expense from operations differs f rom 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: 2021 2020 2019 Federal statutory rate 21.0 % 21.0 % 21.0 % State income tax on pretax income, net of federal tax effect 7.0 7.0 7.1 Increases (decreases) in tax from: Wind PTCs (27.8) (19.3) (11.8) Plant regulatory differences (a) (8.1) (7.2) (7.4) Other tax credits, net NOL & tax credit allowances (1.4) (1.2) (1.5) Change in unrecognized tax benefits 0.5 1.0 0.5 NOL Carryback — (2.1) — Other, net 0.2 (0.2) 0.1 Effective income tax rate (8.6) % (1.0) % 8.0 % (a) 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 credits are offset by corresponding revenue reductions. Components of income tax expense for years ended Dec. 31: (Millions of Dollars) 2021 2020 2019 Current federal tax (benefit) expense $ (10) $ 41 $ 80 Current state tax (benefit) expense (1) 12 8 Current change in unrecognized tax expense (benefit) 1 9 (1) Deferred federal tax benefit (87) (102) (86) Deferred state tax expense 49 38 43 Deferred change in unrecognized tax expense (benefit) 2 (3) 4 Deferred ITCs (2) (1) (1) Total income tax (benefit) expense $ (48) $ (6) $ 47 Components of deferred income tax expense as of Dec. 31: (Millions of Dollars) 2021 2020 2019 Deferred tax expense excluding items below $ 109 $ 61 97 Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities (145) (127) (135) Tax expense allocated to other comprehensive income, adoption of ASC Topic 326, and other — (1) (1) Deferred tax benefit $ (36) $ (67) $ (39) Components of the net deferred tax liability as of Dec. 31: (Millions of Dollars) 2021 2020 (a) Deferred tax liabilities: Differences between book and tax bases of property $ 2,679 $ 2,482 Regulatory assets 260 270 Operating lease assets 123 147 Deferred fuel costs 92 7 Pension expense 73 72 Other 13 7 Total deferred tax liabilities $ 3,240 $ 2,985 Deferred tax assets: Tax credit carryforward $ 782 $ 614 Regulatory Liabilities 325 349 Operating lease liabilities 123 147 NOL and tax credit valuation allowances (64) (59) Other employee benefits 32 38 NOL carryforward 43 12 Deferred ITCs 5 5 Other 45 39 Total deferred tax assets $ 1,291 $ 1,145 Net deferred tax liability $ 1,949 $ 1,840 (a) Prior periods have been reclassified to conform to current year presentation.

Fair Value of Financial Assets

Fair Value of Financial Assets and Liabilities	12 Months Ended
	Dec. 31, 2021
Fair Value Disclosures [Abstract]
Fair Value of Financial Assets and Liabilities	Fair Value Measurements Accounting guidance for fair value measurements and disclosures provides a single definition of fair value and requires disclosures about assets and liabilities measured at fair value. A hierarchical framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value is established by this guidance. • 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 highly liquid and actively traded instruments with quoted prices. • Level 2 — Pricing inputs are other than quoted 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 are those valued with models requiring significant management judgment or estimation. Cash equivalents — The fair values of cash equivalents are generally based on cost plus accrued interest; money market funds are measured using quoted NAV. 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 fund investments 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’ investments may be redeemed with proper notice, however, 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 — The fair values of interest rate derivatives are based on broker quotes that utilize current market interest rate forecasts. Commodity derivatives — The methods used to measure the fair value of commodity derivative forwards and options utilize forward prices and volatilities, as well as pricing adjustments for specific delivery locations, and are generally assigned a Level 2 classification. When contractual settlements relate to inactive delivery locations or extend to periods beyond those readily observable on active exchanges or quoted by brokers, the significance of the use of less observable forecasts of forward prices and volatilities 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 value of an FTR is derived from, and designed to offset, the cost 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 an FTR. If forecasted costs of electric transmission congestion increase or decrease for a given FTR path, the value of that particular FTR instrument will likewise increase or decrease. Given the limited observability of certain inputs to the value of FTRs between auction processes, including expected plant operating schedules and retail and wholesale demand, fair value measurements for FTRs have been assigned a Level 3. Non-trading monthly FTR settlements are included in fuel and purchased energy cost recovery mechanisms and therefore changes in the fair value of the yet to be settled portions of most FTRs are deferred as a regulatory asset or liability. Given this regulatory treatment and the limited magnitude of NSP-Minnesota’s FTRs relative to its electric utility operations, the numerous unobservable quantitative inputs pertinent to the value of FTRs are immaterial to the consolidated financial statements of NSP-Minnesota. 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 $1.3 billion and $981 million as of Dec. 31, 2021 and 2020, respectively, and unrealized losses were $7 million and $5 million as of Dec. 31, 2021 and 2020, respectively. Non-derivative instruments with recurring fair value measurements in the nuclear decommissioning fund: 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 sheet, which also includes $52 million of rabbi trust assets and miscellaneous investments. Dec. 31, 2020 Fair Value (Millions of Dollars) Cost Level 1 Level 2 Level 3 NAV Total Nuclear decommissioning fund (a) Cash equivalents $ 40 $ 40 $ — $ — $ — $ 40 Commingled funds 787 — — — 1,041 1,041 Debt securities 528 — 572 13 — 585 Equity securities 446 1,109 2 — — 1,111 Total $ 1,801 $ 1,149 $ 574 $ 13 $ 1,041 $ 2,777 (a) Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $53 million of rabbi trust assets and miscellaneous investments. For the years ended Dec. 31, 2021 and 2020, 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, 2021: Final Contractual Maturity (Millions of Dollars) Due in 1 year or Less Due in 1 to 5 Years Due in 5 to 10 Years Due after 10 Years Total Debt securities $ 4 $ 149 $ 208 $ 314 $ 675 Rabbi Trusts NSP-Minnesota has established a rabbi trust to provide partial funding for future deferred compensation plan distributions. Cost and fair value of assets held in rabbi trusts: Dec. 31, 2021 Fair Value (Millions of Dollars) Cost Level 1 Level 2 Level 3 Total Rabbi Trusts (a) Mutual funds $ 10 $ 13 $ — $ — $ 13 Total $ 10 $ 13 $ — $ — $ 13 (a) Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet. Dec. 31, 2020 Fair Value (Millions of Dollars) Cost Level 1 Level 2 Level 3 Total Rabbi Trusts (a) Cash equivalents $ 1 $ 1 $ — $ — $ 1 Mutual funds 14 16 — — 16 Total $ 15 $ 17 $ — $ — $ 17 (a) Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet. Derivative Instruments Fair Value Measurements 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, utility commodity prices and vehicle fuel prices. Interest Rate Derivatives — NSP-Minnesota enters into various instruments that effectively fix the yield or price on a specified benchmark interest rate for an anticipated debt issuance for a specific period. These derivative instruments are generally designated as cash flow hedges for accounting purposes, with changes in fair value prior to settlement recorded as other comprehensive income. As of Dec. 31, 2021, accumulated other comprehensive loss related to settled interest rate derivatives included $1 million of net losses expected to be reclassified into earnings during the next 12 months as the hedged interest rate transactions impact earnings. As of Dec. 31, 2021, NSP-Minnesota had no unsettled interest rate derivatives. Wholesale and Commodity Trading Risk — 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 activities governed by this policy. 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, as well as for trading purposes. This could include the purchase or sale of energy or energy-related products, natural gas to generate electric energy, natural gas for resale, FTRs, vehicle fuel, and weather derivatives. As of Dec. 31, 2021, NSP-Minnesota had no commodity contracts designated as cash flow hedges. NSP-Minnesota may enter into derivative instruments that mitigate commodity price risk on behalf of electric and natural gas customers, but may not be 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. NSP-Minnesota enters into commodity derivative instruments for trading purposes not directly related to commodity price risks associated with serving its electric and natural gas customers. Changes in the fair value of these commodity derivatives are recorded in electric operating revenues, net of amounts credited to customers under margin-sharing mechanisms. Gross notional amounts of commodity forwards, options and FTRs: (Amounts in Millions) (a)(b) Dec. 31, 2021 Dec. 31, 2020 MWh of electricity 57 65 MMBtu of natural gas 85 83 (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, 2021, eight of NSP-Minnesota’s 10 most significant counterparties for these activities, comprising $33 million or 63% of this credit exposure, had investment grade credit ratings from S&P, Moody’s or Fitch Ratings. One of the 10 most significant counterparties, comprising $17 million or 34% of this credit exposure, was not rated by these external agencies, but based on NSP-Minnesota’s internal analysis, had credit quality consistent with investment grade. One of these significant counterparties, comprising an immaterial amount or less than 1% of this credit exposure, had credit quality less than investment grade, based on internal analysis. Six of these significant counterparties are municipal or cooperative electric entities, RTOs or other utilities. Qualifying Cash Flow Hedges — Financial impact of qualifying interest rate and vehicle fuel 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: (Millions of Dollars) 2021 2020 2019 Accumulated other comprehensive loss related to cash flow hedges at Jan. 1 $ (19) $ (20) $ (20) After-tax net realized losses on derivative transactions reclassified into earnings 2 1 — Accumulated other comprehensive loss related to cash flow hedges at Dec. 31 $ (17) $ (19) $ (20) Impact of derivative activity: Pre-Tax Fair Value (Millions of Dollars) Accumulated Other Comprehensive Loss Regulatory (Assets) and Liabilities 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 $ — $ — Year Ended Dec. 31, 2019 Other derivative instruments Electric commodity $ — $ 2 Natural gas commodity — (3) Total $ — $ (1) Pre-Tax (Gains) Losses Pre-Tax Gains (Losses) (Millions of Dollars) Accumulated Other Comprehensive Loss Regulatory 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) Total $ — $ (2) $ 45 Pre-Tax (Gains) Losses Pre-Tax Gains (Losses) (Millions of Dollars) Accumulated Other Comprehensive Loss Regulatory 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) Total $ — $ (1) $ (9) Pre-Tax (Gains) Losses Pre-Tax Gains (Losses) (Millions of Dollars) Accumulated Other Comprehensive Loss Regulatory Year Ended Dec. 31, 2019 Other derivative instruments Electric commodity $ — $ 1 (c) $ — Natural gas commodity — 1 (d) (3) (d) Total $ — $ 2 $ (3) (a) 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. (b) Amounts are recorded to cost of natural gas sold and transported. These derivative settlement gains and losses are shared with natural gas customers through purchased natural gas cost-recovery mechanisms and reclassified out of income as regulatory assets and liabilities, as appropriate. (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. (d) Amounts are recorded to cost of natural gas sold and transported. These derivative settlement gains and losses are shared with natural gas customers through purchased natural gas cost-recovery mechanisms and reclassified out of income as regulatory assets and liabilities, as appropriate. NSP-Minnesota had no derivative instruments designated as fair value hedges during the years ended Dec. 31, 2021, 2020 and 2019. Credit Related Contingent Features — Contract provisions for derivative instruments that NSP-Minnesota enters into, including those accounted for as normal purchase-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 NSP-Minnesota’s credit ratings are downgraded below its investment grade credit rating by any of the major credit rating agencies. As of Dec. 31, 2021 and 2020, there were $3 million and $4 million derivative instruments in a liability position 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 the other financing arrangements related to payment terms or other covenants. As of Dec. 31, 2021 and 2020, there were approximately $48 million and $14 million of derivative instruments in a liability position with such underlying contract provisions, respectively. Provisions allow counterparties to seek performance assurance, including cash collateral, in the event that NSP-Minnesota’s ability to fulfill its contractual obligations is reasonably expected to be impaired. NSP-Minnesota had no collateral posted related to adequate assurance clauses in derivative contracts as of Dec. 31, 2021 and 2020. Recurring Fair Value Measurements — NSP-Minnesota’s derivative assets and liabilities measured at fair value on a recurring basis were as follows: Dec. 31, 2021 Dec. 31, 2020 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 $ 9 $ 40 $ 22 $ 71 $ (53) $ 18 $ 1 $ 26 $ — $ 27 $ (25) $ 2 Electric commodity — — 30 30 (1) 29 — — 13 13 (1) 12 Natural gas commodity — 6 — 6 — 6 — 3 — 3 — 3 Total current derivative assets $ 9 $ 46 $ 52 $ 107 $ (54) $ 53 $ 1 $ 29 $ 13 $ 43 $ (26) $ 17 Noncurrent derivative assets Other derivative instruments: Commodity trading $ 6 $ 34 $ 35 $ 75 $ (42) $ 33 $ 7 $ 39 $ — $ 46 $ (41) $ 5 Total noncurrent derivative assets $ 6 $ 34 $ 35 $ 75 $ (42) $ 33 $ 7 $ 39 $ — $ 46 $ (41) $ 5 Dec. 31, 2021 Dec. 31, 2020 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 $ 13 $ 58 $ 4 $ 75 $ (58) $ 17 $ 3 $ 18 $ 10 $ 31 $ (25) $ 6 Electric commodity — — 1 1 (1) — — — 1 1 (1) — Natural gas commodity — 4 — 4 — 4 — 2 — 2 — 2 Total current derivative liabilities $ 13 $ 62 $ 5 $ 80 $ (59) 21 $ 3 $ 20 $ 11 $ 34 $ (26) 8 PPAs (b) 14 14 Current derivative instruments $ 35 $ 22 Noncurrent derivative liabilities Other derivative instruments: Commodity trading $ 15 $ 48 $ 26 $ 89 $ (53) $ 36 $ 2 $ 35 $ 13 $ 50 $ (27) $ 23 Total noncurrent derivative liabilities $ 15 $ 48 $ 26 $ 89 $ (53) 36 $ 2 $ 35 $ 13 $ 50 $ (27) 23 PPAs (b) 35 48 Noncurrent derivative instruments $ 71 $ 71 (a) NSP-Minnesota nets derivative instruments and related collateral on its consolidated balance sheets when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Dec. 31, 2021 and 2020. At Dec. 31, 2021 derivative assets and liabilities include no obligations to return cash collateral. At Dec. 31, 2020 derivative assets and liabilities include $15 million of obligations to return cash collateral. At Dec. 31, 2021 and 2020, derivative assets and liabilities include the rights to reclaim cash collateral of $16 million and $1 million, respectively. The counterparty netting excludes settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements. (b) During 2006, Xcel Energy qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities. Changes in Level 3 commodity derivatives for the years ended Dec. 31, 2021, 2020 and 2019: Year Ended Dec. 31 (Millions of Dollars) 2021 2020 2019 Balance at Jan. 1 $ (11) $ 5 $ 14 Purchases 54 28 17 Settlements (82) (49) (28) Net transactions recorded during the period: Gains (losses) recognized in earnings (a) 72 (8) 3 Net gains (losses) recognized as regulatory assets and liabilities 23 13 (1) Balance at Dec. 31 $ 56 $ (11) $ 5 (a) Level 3 losses and gains recognized in earnings are subject to offsetting gains and losses of derivative instruments categorized as levels 1 and 2 in the income statement. Fair Value of Long-Term Debt As of Dec. 31, other financial instruments for which the carrying amount did not equal fair value: 2021 2020 (Millions of Dollars) Carrying Amount Fair Value Carrying Amount Fair Value Long-term debt, including current portion $ 6,747 $ 7,761 $ 5,904 $ 7,391

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 1.96, 1.78 and 2.74 percent in 2021, 2020, and 2019, 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, 2021 and 2020 were $43 million and $43 million, respectively, of which $3 million and $4 million was attributable to NSP-Minnesota in 2021 and 2020, respectively. In 2021 and 2020, Xcel Energy recognized net benefit cost for the SERP and nonqualified plans of $4 million and $6 million, respectively, of which $1 million was attributable to NSP-Minnesota in 2020 and the cost for 2021 was immaterial. Xcel Energy, which includes NSP-Minnesota, 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 long-term projected return levels. 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 2021 were above the assumed level of 6.60%. • Investment returns in 2020 were above the assumed level of 7.10%. • Investment returns in 2019 were above the assumed level of 7.10%. • In 2022, NSP-Minnesota’s expected investment-return assumption is 6.60%. 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 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, 2021 (a) Dec. 31, 2020 (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 $ 31 $ — $ — $ — $ 31 $ 52 $ — $ — $ — $ 52 Commingled funds 304 — — 274 578 369 — — 284 653 Debt securities — 219 1 — 220 — 167 1 — 168 Equity securities 16 — — — 16 20 — — — 20 Other — 1 — 7 8 3 1 — — 4 Total $ 351 $ 220 $ 1 $ 281 $ 853 $ 444 $ 168 $ 1 $ 284 $ 897 (a) See Note 8 for further information on 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, 2021 (a) Dec. 31, 2020 (a) (Millions of Dollars) Level 1 Level 2 Level 3 Measured at NAV Total Level 1 Level 2 Level 3 Measured at NAV Total Commingled funds $ — $ — $ — $ 1 $ 1 $ — $ — $ — $ — $ — Debt securities — 2 — — 2 — 2 — — 2 Total $ — $ 2 $ — $ 1 $ 3 $ — $ 2 $ — $ — $ 2 (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 2021 or 2020. Funded Status — Benefit obligations for both pension and postretirement plans decreased from Dec. 31, 2020 to Dec. 31, 2021, 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) 2021 2020 2021 2020 Change in Benefit Obligation: Obligation at Jan. 1 $ 989 $ 942 $ 73 $ 76 Service cost 30 27 — — Interest cost 25 31 2 2 Plan amendments 1 — — — Actuarial (gain) loss (28) 84 (5) 2 Benefit payments (140) (95) (6) (7) Obligation at Dec. 31 $ 877 $ 989 $ 64 $ 73 Change in Fair Value of Plan Assets: Fair value of plan assets at Jan. 1 $ 897 $ 815 $ 2 $ 3 Actual return on plan assets 62 133 — — Employer contributions 34 44 7 6 Benefit payments (140) (95) (6) (7) Fair value of plan assets at Dec. 31 $ 853 $ 897 $ 3 $ 2 Funded status of plans at Dec. 31 $ (24) $ (92) $ (61) $ (71) Amounts recognized in the Consolidated Balance Sheet at Dec. 31: Current liabilities $ — $ — $ (3) $ (5) Noncurrent liabilities (24) (92) (58) (66) Net amounts recognized $ (24) $ (92) $ (61) $ (71) Pension Benefits Postretirement Benefits Significant Assumptions Used to Measure Benefit Obligations: 2021 2020 2021 2020 Discount rate for year-end valuation 3.08 % 2.71 % 3.09 % 2.65 % Expected average long-term increase in compensation level 3.75 % 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 5.30 % 5.50 % Health care costs trend rate — initial: Post-65 N/A N/A 4.90 % 5.00 % 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 4 5 The accumulated benefit obligation for the pension plan was $811 million and $912 million as of Dec. 31, 2021 and 2020, 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) 2021 2020 2019 2021 2020 2019 Service cost $ 30 $ 27 $ 25 $ — $ — $ — Interest cost 25 31 37 2 2 3 Expected return on plan assets (52) (55) (54) — — — Amortization of prior service cost — — — (3) (3) (3) Amortization of net loss 34 33 30 2 1 2 Settlement charge (a) 35 — — — — — Net periodic pension cost 72 36 38 1 — 2 Effects of regulation (44) (4) (5) — — — Net benefit cost recognized for financial reporting $ 28 $ 32 $ 33 $ 1 $ — $ 2 Significant Assumptions Used to Measure Costs: Discount rate 2.71 % 3.49 % 4.31 % 2.65 % 3.47 % 4.32 % 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 7.10 7.10 4.10 4.50 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 2021, as a result of lump-sum distributions during the 2021 plan year, NSP-Minnesota recorded a total pension settlement charge of $35 million in 2021, which was not recognized due to the effects of regulation. There were no settlement charges recorded to the qualified pension plans in 2020 and 2019. Pension Benefits Postretirement Benefits (Millions of Dollars) 2021 2020 2021 2020 Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost: Net loss $ 307 $ 414 $ 31 $ 37 Prior service credit — — (4) (6) Total $ 307 $ 414 $ 27 $ 31 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 $ 25 $ 29 $ — $ — Noncurrent regulatory assets 282 385 25 29 Deferred income taxes — — 1 1 Net-of-tax accumulated other comprehensive income — — 1 1 Total $ 307 $ 414 $ 27 $ 31 Measurement date Dec 31, 2021 Dec 31, 2020 Dec 31, 2021 Dec 31, 2020 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 2019 - 2022 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 2022, of which $5 million is 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. • $154 million in 2019, of which $47 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: • $9 million in 2022, of which $6 million is attributable to NSP-Minnesota. • $15 million in 2021, of which $8 million, was attributable to NSP-Minnesota. • $11 million in 2020, of which $6 million was attributable to NSP-Minnesota. • $15 million in 2019, of which $8 million was attributable to NSP-Minnesota. Target asset allocations: Pension Benefits Postretirement Benefits 2021 2020 2021 2020 Domestic and international equity securities 33 % 35 % 15 % 15 % Long-duration fixed income and interest rate swap securities 37 35 — — Short-to-intermediate fixed income securities 11 13 71 72 Alternative investments 17 15 8 9 Cash 2 2 6 4 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 2019, the Pension Protection Act measurement concept was extended beyond 2019 for NSP bargaining terminations and retirements to Dec. 31, 2022. In 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 Expected Net Projected 2022 $ 118 $ 6 $ — $ 6 2023 72 6 — 6 2024 68 5 — 5 2025 67 5 — 5 2026 64 5 — 5 2027-2031 292 18 — 18 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 $12 million in 2021, 2020 and 2019. 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, 2021
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. Minnesota Winter Storm Uri Costs — In its Minnesota jurisdiction, NSP-Minnesota is participating in a contested case regarding the prudency of incremental natural gas costs incurred during Winter Storm Uri. Other parties to the case have recommended significant cost disallowances, and while ultimate resolution of the matter is uncertain, it is reasonably possible that the MPUC could disallow certain deferred costs, resulting in earnings losses. The OAG recommended the MPUC deny recovery of up to $179 million, the largest recommendation among the intervenor positions. NSP-Minnesota strongly disagrees with the recommendations of the DOC, OAG and CUB, and believes that it acted prudently and according to MPUC approved procedures for the best interest of its customers and stakeholders. NSP-Minnesota filed rebuttal testimony in January 2022 detailing its position that the disallowances recommended by other parties lack any merit in the prudency review given the pertinent facts regarding NSP-Minnesota’s actions before, during and after the storm event. An MPUC decision is expected in the summer of 2022. 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 FCA. In March 2019, the MPUC approved NSP-Minnesota’s settlement refund proposal. Additionally, the MPUC decided to withhold any decision as to NSP-Minnesota’s prudence in connection with the incident at Sherco Unit 3 until after conclusion of an appeal pending between GE and NSP-Minnesota’s insurers. In February 2020, the Minnesota Court of Appeals affirmed the district court’s judgment in favor of GE. In 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 OAG and DOC recommended that NSP-Minnesota refund approximately $17 million of replacement power costs previously recovered through the FCA. 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 pending. A loss related to this matter is deemed remote. Westmoreland Arbitration — In November 2014, insurers of the Westmoreland Coal Company filed an arbitration demand against NSP-Minnesota, Southern Minnesota Municipal Power Agency and Western Fuels Association, seeking recovery of alleged $36 million of business losses due to a turbine failure at Sherco Unit 3. The Westmoreland insurers claim NSP-Minnesota’s invocation of the force majeure clause to stop the supply of coal was improper because the incident was allegedly caused by NSP-Minnesota’s failure to conform to industry maintenance standards. NSP-Minnesota denies the claims asserted by the Westmoreland insurers and believes it properly stopped the supply of coal based upon the force majeure provision . A final hearing has been scheduled for October 2022. The parties are also required to participate in mediation, which has been scheduled for the first quarter of 2022. At this stage of the proceeding, a reasonable estimate of damages or range of damages cannot be determined. 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%. In September 2016, the FERC issued an order (Opinion No. 551) granting a 10.32% base ROE effective for the first complaint period of Nov. 12, 2013 to Feb. 11, 2015 and subsequent to the date of the order. The D.C Circuit subsequently vacated and remanded Opinion No. 551. In November 2019, the FERC issued an order (Opinion No. 569), which set the MISO base ROE at 9.88%, effective Sept. 28, 2016 and for the first complaint period. The FERC also dismissed the second complaint. In December 2019, MISO TOs filed a request for rehearing regarding the new ROE methodology announced in Opinion No. 569. Customers also filed requests for rehearing claiming, among other points, that the FERC erred by dismissing the second complaint without refunds. In May 2020, the FERC issued an order (Opinion No. 569-A) which granted rehearing in part to Opinion 569 and further refined the FERC’s ROE methodology, most significantly to incorporate the risk premium model (in addition to the discounted cash flow and capital asset pricing models), resulting in a new base ROE of 10.02%, effective Sept. 28, 2016 and for the first complaint period. The FERC also affirmed its decision in Opinion No. 569 to dismiss the second complaint. In November 2020, the FERC issued an order (Opinion No. 569-B) in response to rehearing requests. The FERC corrected certain inputs to its ROE calculation model, did not change the ROE effective Sept. 28, 2016, and for the first MISO complaint period and upheld its decision to deny refunds for the second complaint period. NSP-Minnesota has recognized a liability for its best estimate of final refunds to customers. Eac h 10 basis point reduction in ROE for the first complaint period, second complaint period and subsequent period relative to amounts accrued would reduce Xcel Energy’s net income by $1 million, $1 million and $2 million, respectively. The MISO TOs and various parties have filed petitions for review of Opinion Nos. 569, 569-A and 569-B at the D.C. Circuit. Oral arguments were held in late 2021 and a decision is expected by the end of the third quarter of 2022. 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 currently investigating, remediating or performing post closure actions at seven historical MGP, landfill or other disposal sites across its service territories, excluding sites that are being addressed under current coal ash regulations (see below). 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. In August 2020, the EPA published its final rule to implement closure by April 2021 for all CCR impoundments affected by the August 2018 D.C. Circuit ruling. This final rule required NSP-Minnesota to expedite closure plans for one impoundment. In October 2020, NSP-Minnesota completed construction and placed in service a new impoundment to replace the clay lined impoundment. With the new ash pond in service, NSP-Minnesota has initiated closure activities for the existing ash pond at an estimated cost of $4 million. NSP-Minnesota has five years to complete closure activities. Closure costs for existing impoundments are included in the calculation of the ARO. Federal CWA Waters of the U.S. Rule — NSP-Minnesota is monitoring ongoing changes to the definition of Waters of the U.S. under the CWA. Regardless of which definition is applicable in the states in which we operate, NSP-Minnesota does not anticipate that compliance costs will be material. Federal CWA ELG — In 2015, the EPA issued a final ELG rule for power plants that discharge treated effluent to surface waters as well as utility-owned landfills that receive CCRs. In October 2020, the EPA published a final rule revising the regulations. The retirement of units affected by the final ELG rule is subject to regulatory approval. The exact total cost of ELG compliance is therefore uncertain but NSP-Minnesota does not anticipate that compliance costs will be material. Federal CWA Section 316(b) — The federal CWA requires the EPA to regulate cooling water intake structures to assure that these structures reflect the best technology available for minimizing impingement and entrainment of aquatic species. NSP-Minnesota estimates the likely future cost for complying with impingement and entrainment requirements is approximately $36 million, to be incurred between 2022 and 2028. NSP-Minnesota believes six plants could be required to make improvements to reduce impingement and entrainment. The exact total cost of the impingement and entrainment improvements is uncertain, but could be up to $188 million. NSP-Minnesota anticipates these costs will be fully recoverable through regulatory mechanisms. Environmental Requirements — Air Regional Haze Rules — The regional haze program requires sulfur dioxide, nitrogen oxide and particulate matter emission controls at power plants to reduce visibility impairment in national parks and wilderness areas. The program includes best available retrofit technology and reasonable further progress. The regional haze first planning period requirements were approved by the EPA and implemented by 2014. All states are now subject to a second round of regional haze planning/rulemaking, focusing on additional reductions to meet reasonable progress requirements. Any additional impacts to NSP-Minnesota facilities are expected to be minimal. AROs — AROs have been recorded for NSP-Minnesota’s assets. For nuclear assets, the ARO is associated with the decommissioning of NSP-Minnesota nuclear generating plants. Aggregate fair value of NSP-Minnesota’s legally restricted assets, for funding future nuclear decommissioning, was $3.3 billion and $2.8 billion for 2021 and 2020, respectively. NSP-Minnesota’s AROs were as follows: 2021 (Millions Jan. 1, 2021 Amounts Incurred (a) Accretion Cash Flow Revisions (b) Dec. 31, 2021 (c) Electric Nuclear $ 1,957 $ — $ 99 $ — $ 2,056 Wind 270 101 13 — 384 Steam and other production 67 6 2 (2) 73 Distribution 16 — — — 16 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. (c) There were no ARO amounts settled in 2021. 2020 (Millions Jan. 1, 2020 Amounts Incurred (a) Amounts Settled (b) Accretion Cash Flow Revisions (c) Dec. 31, 2020 Electric Nuclear $ 2,068 $ — $ — $ 105 $ (216) $ 1,957 Wind 113 90 — 7 60 270 Steam and other production 47 — (3) 2 21 67 Distribution 15 — — 1 — 16 Miscellaneous — — — — — — Natural gas Transmission and distribution 36 — — 2 1 39 Common Miscellaneous 1 — — — — 1 Total liability $ 2,280 $ 90 $ (3) $ 117 $ (134) $ 2,350 (a) Amounts incurred relate to the wind farms placed in service in 2020 (Blazing Star 1, Crowned Ridge, Jeffers and Community Wind North). (b) Amounts settled related to closure of certain ash containment facilities. (c) In 2020, AROs were revised for changes in timing and estimates of cash flows. Revisions in the nuclear AROs were driven by reductions in spent fuel cooling time requirements in the nuclear triennial filing coupled with decreasing interest rates. Changes in wind AROs were driven by new dismantling studies. Revisions in steam and other production AROs primarily related to changes in cost estimates for remediation of ash containment facilities. Indeterminate AROs — Outside of the recorded asbestos AROs, other plants or buildings may contain asbestos due to the age of many of NSP-Minnesota’s facilities, but no confirmation or measurement of the cost of removal could be determined as of Dec. 31, 2021. 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 $13.5 billion under the Price-Anderson amendment to the Atomic Energy Act. NSP-Minnesota has secured $450 million of coverage for its public liability exposure with a pool of insurance companies. The remaining $13.0 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 $21 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 $11 million for business interruption insurance and $33 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 47 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. 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 operating license and be completed by 2091. 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. 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. Obligations for decommissioning are expected to be funded 100% by the external decommissioning trust fund. The cost study assumes the external decommissioning fund will earn an after-tax return between 5.23% and 6.30%. Realized and unrealized gains on fund investments are deferred as an offset of NSP-Minnesota’s regulatory asset for nuclear decommissioning costs. Decommissioning costs are quantified in 2014 dollars. Escalation rates are 4.36% for plant removal activities and 3.36% for fuel management and site restoration activities. NSP-Minnesota had $3.3 billion of assets held in external decommissioning trusts at Dec. 31, 2021. The following table summarizes the funded status of NSP-Minnesota’s decommissioning obligation. Xcel Energy believes future decommissioning costs will continue to be recovered in customer rates. The following amounts were prepared on a regulatory basis and not directly recorded in the financial statements as an ARO. Regulatory Basis (Millions of Dollars) 2021 2020 Estimated decommissioning cost obligation from most recently $ 3,012 $ 3,012 Effect of escalating costs 1,006 844 Estimated decommissioning cost obligation (in current dollars) 4,018 3,856 Effect of escalating costs to payment date 7,187 7,349 Estimated future decommissioning costs (undiscounted) 11,205 11,205 Effect of discounting obligation (using average risk-free interest rate of 1.96% and 1.64% for 2021 and 2020, respectively) (4,651) (4,181) Discounted decommissioning cost obligation $ 6,554 $ 7,024 Assets held in external decommissioning trust $ 3,256 $ 2,777 Underfunding of external decommissioning fund compared to 3,298 4,247 Calculations and data used by the regulator in approving NSP-Minnesota’s rates are useful in assessing future cash flows. Regulatory basis information is a means to reconcile amounts previously provided to the MPUC and utilized for regulatory purposes to amounts used for financial reporting. Reconciliation of the discounted decommissioning cost obligation - regulated basis to the ARO recorded in accordance with GAAP: (Millions of Dollars) 2021 2020 Discounted decommissioning cost obligation - regulated basis $ 6,554 $ 7,024 Differences in discount rate and market risk premium (2,209) (2,628) O&M costs not included for GAAP (1,584) (1,734) ARO differences between 2020 and 2014 cost studies (705) (705) Nuclear production decommissioning ARO - GAAP $ 2,056 $ 1,957 Decommissioning expenses recognized as a result of regulation: (Millions of Dollars) 2021 2020 2019 Annual decommissioning recorded as depreciation expense: (a) (b) $ 22 $ 20 $ 20 (a) Decommissioning expense does not include depreciation of the capitalized nuclear asset retirement costs. (b) Decommissioning expenses in 2021, 2020 and 2019 include Minnesota’s retail jurisdiction annual funding requirement of approximately $14 million. The 2017 nuclear decommissioning filing, effective Jan. 1, 2019, has been approved by the MPUC. In March 2020, the MPUC approved for NSP-Minnesota to delay any increase to the annual funding requirement until 2021. In December 2020, the MPUC verbally approved for NSP-Minnesota to delay any increase to the annual funding requirement until 2022. Also, as of December 2020, NSP-Minnesota submitted a Petition for approval of the 2022 - 2024 Nuclear Decommissioning Study and Assumptions. Contemplated but not proposed in this filing, was the 10-year extension of the license to operate the Monticello Plant, moving the planned retirement date from 2030 to 2040. The 2019 Preferred Integrated Resource Plan Supplement does include a 10-year extension of the license. On Feb. 8, 2022, the MPUC ruled on and approved the 10-year extension for the Monticello nuclear facility. 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, 2021 Dec. 31, 2020 PPAs $ 556 $ 558 Other 74 74 Gross operating lease ROU assets 630 632 Accumulated amortization (222) (144) Net operating lease ROU assets $ 408 $ 488 Components of lease expense: (Millions of Dollars) 2021 2020 2019 Operating leases PPA capacity payments $ 96 $ 89 $ 76 Other operating leases (a) 8 8 9 Total operating lease expense (b) $ 104 $ 97 $ 85 (a) Includes short-term lease expense o f $2 million , $2 million and $1 million for 2021, 2020 and 2019, 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, 2021: (Millions of Dollars) PPA (a) (b) Operating Leases Other Operating Leases Total Leases 2022 $ 96 $ 9 $ 105 2023 98 12 110 2024 100 7 107 2025 80 7 87 2026 40 7 47 Thereafter — 31 31 Total minimum obligation 414 73 487 Interest component of obligation (32) (12) (44) Present value of minimum obligation $ 382 $ 61 443 Less current portion (90) Noncurrent operating lease liabilities $ 353 Weighted-average remaining lease term in years 8.5 (a) Amounts do not include PPAs accounted for as executory contracts and/or contingent payments, such as energy payments on renewable PPAs. (b) PPA operating leases contractually expire at various dates through 2039. PPAs and Fuel Contracts Non-Lease PPAs — NSP-Minnesota has entered into PPAs with other utilities and energy suppliers for purchased power to meet system load and energy requirements, operating reserve obligations and as part of wholesale and commodity trading activities. In general, these agreements provide for energy payments, based on actual energy delivered and 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 $149 million, $112 million and $102 million in 2021, 2020 and 2019, respectively. Included in electric fuel and purchased power expenses for PPAs accounted for as executory contracts were payments for capacity of $55 million, $52 million and $54 million in 2021, 2020 and 2019, 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, 2021, 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) 2022 $ 60 $ 165 2023 61 169 2024 63 174 2025 26 53 2026 9 10 Thereafter 10 38 Total (b) $ 229 $ 609 (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 2022 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, 2021: (Millions of Dollars) Coal Nuclear fuel Natural gas Natural gas 2022 $ 219 $ 89 $ 95 $ 128 2023 79 109 — 114 2024 48 82 — 108 2025 1 119 — 98 2026 1 29 — 97 Thereafter 1 309 — 107 Total (a) $ 349 $ 737 $ 95 $ 652 (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 1,347 MW of capacity under long-term PPAs at both Dec. 31, 2021 and 2020 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, 2021
Stockholders' Equity Note [Abstract]
Other Comprehensive Income	Changes in accumulated other comprehensive loss, net of tax, for the years ended Dec. 31: 2021 (Millions of Dollars) Gains and Losses on 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: Interest rate derivatives, net of tax of $— 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. 2020 (Millions of Dollars) Gains and Losses on Cash Flow Hedges Defined Benefit Pension and Postretirement Items Total Accumulated other comprehensive loss at Jan. 1 $ (20) $ (3) $ (23) Losses reclassified from net accumulated other comprehensive loss: Interest rate derivatives, net of tax of $— 1 (a) — 1 Net current period other comprehensive income 1 — 1 Accumulated other comprehensive loss at Dec. 31 $ (19) $ (3) $ (22) (a) Included in interest charges.

Segments and Related Informatio

Segments and Related Information	12 Months Ended
	Dec. 31, 2021
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) 2021 2020 2019 Regulated Electric Operating revenues — external (a) $ 5,094 $ 4,571 $ 4,506 Intersegment revenue 1 1 1 Total revenues $ 5,095 $ 4,572 $ 4,507 Depreciation and amortization 869 773 742 Interest charges and financing costs 240 221 205 Income tax (benefit) expense (53) (14) 36 Net income 566 553 491 Regulated Natural Gas Operating revenues — external (b) $ 623 $ 493 $ 571 Intersegment revenue 1 — 1 Total revenues $ 624 $ 493 $ 572 Depreciation and amortization 56 51 49 Interest charges and financing costs 18 17 16 Income tax expense 6 7 12 Net income 29 30 40 All Other Total revenues $ 39 $ 37 $ 35 Depreciation and amortization 1 1 — Income tax (benefit) expense (1) 1 (1) Net income 11 8 12 Consolidated Total Total revenues (a)(b) $ 5,758 $ 5,102 $ 5,114 Reconciling eliminations (2) (1) (2) Total operating revenues $ 5,756 $ 5,101 $ 5,112 Depreciation and amortization 926 825 791 Interest charges and financing costs 258 238 221 Income tax (benefit) expense (48) (6) 47 Net income 606 591 543 (a) Operating revenues include $501 million, $440 million and $457 million of affiliate electric revenue for the years ended Dec. 31, 2021, 2020 and 2019, respectively. See Note 13 for further information.

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2021
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) 2021 2020 2019 Operating revenues: Electric $ 501 $ 440 $ 457 Gas 1 1 1 Operating expenses: Purchased power 67 59 61 Transmission expense 121 109 116 Other operating expenses — paid to Xcel Energy Services Inc. 615 584 533 Interest expense — — 1 Accounts receivable and payable with affiliates at Dec. 31: 2021 2020 (Millions of Dollars) Accounts Receivable Accounts Payable Accounts Receivable Accounts Payable NSP-Wisconsin $ 13 $ — $ 6 $ — PSCo 16 — 1 — SPS — 2 — 3 Other subsidiaries of Xcel Energy Inc. — 61 25 63 $ 29 $ 63 $ 32 $ 66

Summarized Quarterly Financial

Summarized Quarterly Financial Data (Unaudited)	12 Months Ended
	Dec. 31, 2021
Quarterly Financial Information Disclosure [Abstract]
Summarized Quarterly Financial Data (Unaudited)	Quarter Ended (Millions of Dollars) March 31, 2021 June 30, 2021 Sept. 30, 2021 Dec. 31, 2021 Operating revenues $ 1,250 $ 1,180 $ 1,388 $ 1,283 Operating income 157 158 314 167 Net income 107 117 246 121 Quarter Ended (Millions of Dollars) March 31, 2020 June 30, 2020 Sept. 30, 2020 Dec. 31, 2020 Operating revenues $ 1,250 $ 1,180 $ 1,388 $ 1,283 Operating income 157 158 314 167 Net income 107 117 246 121

Schedule II, Valuation and Qual

Schedule II, Valuation and Qualifying Accounts	12 Months Ended
	Dec. 31, 2021
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) 2021 2020 2019 Balance at Jan. 1 $ 33 $ 23 $ 24 Additions charged to costs and expenses 24 24 13 Additions charged to other accounts (a) 5 5 7 Deductions from reserves (b) (17) (19) (21) Balance at Dec. 31 $ 45 $ 33 $ 23 (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, 2021
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 in 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 the 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, 2021 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 of recovering deferred costs and returning deferred credits are based on specific ratemaking decisions or precedent for each item. 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 from its balance sheet. Such changes could have a material effect on NSP-Minnesota’s results of operations, financial condition and cash flows.
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 financial statements. NSP-Minnesota defers income taxes 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 NSP-Minnesota’s tax rate changes are generally subject to a normalization method of accounting. Therefore, the revaluation of most of its net deferred taxes upon a tax rate reduction results in the establishment of a net regulatory liability, which would be refundable to utility customers over the remaining life of the related assets. NSP-Minnesota anticipates that a tax rate increase would 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 it over the book depreciable lives of the related property. The requirement to defer and amortize tax credits only applies to federal ITCs related to public utility property. Utility rate regulation also has resulted in the recognition of regulatory assets and liabilities related to income taxes. 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. NSP-Minnesota follows the applicable accounting guidance to measure and disclose uncertain tax positions that it has taken or expects to take in its income tax returns. NSP-Minnesota recognizes a tax position in its 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. NSP-Minnesota reports interest and penalties related to income taxes 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. Planned maintenance activities are charged to operating expense unless the cost represents the acquisition of an additional unit of property or the replacement of an existing unit of property. 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. NSP-Minnesota records depreciation expense 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 recovered in rates as authorized by the appropriate regulatory entities. The amount of removal costs is based on current factors used in existing depreciation rates. Accumulated removal costs are reflected in the consolidated balance sheet as a regulatory liability. Depreciation expense, expressed as a percentage of average depreciable property, was approximately 3.7% for 2021, 3.7% for 2020 and 3.7% for 2019. See Note 3 for further information.
Asset Retirement Obligations	AROs — NSP-Minnesota accounts for AROs under accounting guidance that requires a liability for the fair value of an ARO to be recognized in the period in which it is incurred if it can be reasonably estimated, with the offsetting associated asset retirement 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 depreciated over the useful life of the long-lived asset. Changes resulting from revisions to the timing or amount 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 performed at least every three years and submitted to the state commissions for approval. 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 liability can be reasonably estimated. Costs are deferred as a regulatory asset if it is probable that 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 proceeds. 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. NSP-Minnesota does not recognize a separate financing component of its collections from customers as contract terms are short-term in nature. NSP-Minnesota presents its revenues net of any excise or sales taxes or fees. NSP-Minnesota recognizes physical sales to customers (native load and wholesale) on a gross basis in electric revenues and cost of sales. Revenues and charges for short-term physical wholesale sales of excess energy transacted through RTOs are also recorded on a gross basis. Other revenues and charges settled/facilitated through an RTO are recorded on a net basis in cost of sales. NSP-Minnesota has various rate-adjustment mechanisms that provide for the recovery of natural gas, electric fuel and purchased energy costs. Cost-adjustment tariffs may increase or decrease the level of revenue collected from customers and are revised periodically for differences between the total amount collected under the clauses and the costs incurred. When applicable, fuel cost over-recoveries (the excess of fuel revenue billed to customers over fuel costs incurred) are deferred as regulatory liabilities and under-recoveries (the excess of fuel costs incurred over fuel revenues billed to customers) are deferred as regulatory assets. See Note 6 for further information.
Cash and Cash Equivalents	Cash and Cash Equivalents — NSP-Minnesota considers investments in instruments with a remaining maturity of three months or less at the time of purchase to be cash equivalents.
Accounts Receivable and Allowance for Bad Debts	Accounts Receivable and Allowance for Bad Debts — Accounts receivable are stated at the actual billed amount net of an allowance for bad debts. NSP-Minnesota establishes an allowance for uncollectible receivables based on a policy that reflects its expected exposure to the credit risk of customers. As of Dec. 31, 2021 and 2020, the allowance for bad debts wa s $45 million
Inventory	Inventory — Inventory is recorded at average cost and consisted of the following: (Millions of Dollars) Dec. 31, 2021 Dec. 31, 2020 Inventories Materials and supplies $ 181 $ 178 Fuel 81 90 Natural gas 47 27 Total inventories $ 309 $ 295
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. Cash equivalents are recorded at cost plus accrued interest; money market funds are measured using quoted NAVs. For interest rate derivatives, quoted prices based primarily on observable market interest rate curves are used to establish 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, NSP-Minnesota may use quoted prices for similar contracts or internally prepared valuation models 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 estimate 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 interest rate, utility commodity price and commodity trading activities, 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 and interest rate hedging transactions are recorded as a component of interest expense. 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 a derivative exists and/or whether an instrument may be exempted from derivative accounting if designated as a normal purchase or normal sale.
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. AFUDC 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 for establishing utility rates.
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 costs imposed upon the utility by action of a regulator or legislative body related to an environmental, public safety or other mandate or from other instances where 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 equal to the revenue requirement, which may include incentives and return on rate base items. Billing amounts are revised periodically for differences between total amount collected and revenue earned, which may increase or decrease the level of revenue collected from customers. Alternative revenues arising from these programs are presented on a gross basis and disclosed separately from revenue from contracts with customers. See Note 6 for further information. Conservation Programs — Costs incurred for DSM and CIP programs are deferred if it is probable future revenue will recover the incurred cost. Revenues recognized for incentive programs for the recovery of lost margins and/or conservation performance incentives are limited to amounts expected to be collected within 24 months from the year they are earned. Regulatory assets are recognized to reflect the amount of costs or earned incentives that have not yet been collected from customers.
Emission Allowances	Emission Allowances — Emission allowances are recorded at cost, including broker commission fees. The inventory accounting model is utilized for all emission allowances and 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. 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.

Summary of Significant Accoun_3

Summary of Significant Accounting Policies Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2021
Balance Sheet Related Disclosures [Abstract]
Schedule of Utility Inventory [Table Text Block]	Inventory — Inventory is recorded at average cost and consisted of the following: (Millions of Dollars) Dec. 31, 2021 Dec. 31, 2020 Inventories Materials and supplies $ 181 $ 178 Fuel 81 90 Natural gas 47 27 Total inventories $ 309 $ 295

Property Plant and Equipment (T

Property Plant and Equipment (Tables)	12 Months Ended
	Dec. 31, 2021
Property, Plant and Equipment [Abstract]
Public Utility Property, Plant, and Equipment	Major classes of property, plant and equipment (Millions of Dollars) Dec. 31, 2021 Dec. 31, 2020 Property, plant and equipment, net Electric plant $ 19,154 $ 18,948 Natural gas plant 1,864 1,707 Common and other property 1,007 955 Plant to be retired (a) 719 136 CWIP 984 1,150 Total property, plant and equipment 23,728 22,896 Less accumulated depreciation (7,606) (7,898) Nuclear fuel 3,081 2,970 Less accumulated amortization (2,773) (2,660) Property, plant and equipment, net $ 16,430 $ 15,308
Schedule of Jointly Owned Utility Plants	Joint Ownership of Generation and Transmission Facilities Jointly owned assets as of Dec. 31, 2021: (Millions of Dollars, Except Percent Owned) Plant in Service Accumulated Depreciation Percent Owned Electric generation: Sherco Unit 3 $ 620 $ 451 59 % Sherco common facilities 178 108 80 Sherco substation 5 4 59 Electric transmission: Grand Meadow 11 3 50 Huntley Wilmarth 48 1 50 CapX2020 952 127 51 Total (a) $ 1,814 $ 694 (a) Projects additionally include $7 million in CWIP.

Regulatory Assets and Liabili_2

Regulatory Assets and Liabilities (Tables)	12 Months Ended
	Dec. 31, 2021
Regulatory Assets and Liabilities Disclosure [Abstract]
Regulatory Assets	Components of regulatory assets: (Millions of Dollars) See Note(s) Remaining Amortization Period Dec. 31, 2021 Dec. 31, 2020 Regulatory Assets Current Noncurrent Current Noncurrent Pension and retiree medical obligations 9 Various $ 24 $ 301 $ 26 $ 364 Deferred natural gas and electric energy/fuel costs One five 138 190 8 18 Recoverable deferred taxes on AFUDC Plant lives — 114 — 113 Excess deferred taxes — TCJA 7 Various 10 113 10 122 Sales true-up and revenue decoupling One two 33 56 101 28 Benson biomass PPA termination and asset purchase Eight 10 55 10 65 PI extended power uprate 13 years 4 46 3 49 Contract valuation adjustments (a) 1, 8 Term of related contract 18 34 16 48 Purchased power contracts costs Term of related contract 6 27 4 32 Conservation programs (b) 1 One two 7 22 14 23 Laurentian biomass PPA termination Two 18 18 18 36 Nuclear refueling outage costs 1 One two 37 16 28 10 Losses on reacquired debt Term of related debt 1 11 1 12 Environmental remediation costs 1, 10 Pending future rate cases — 5 1 9 Renewable resources and environmental initiatives One two 170 3 129 1 State commission adjustments Plant lives — 3 — 3 Gas pipeline inspection and remediation costs One two 33 — 26 — Net AROs (c) 1, 10 Various — (316) — (32) Other Various 18 20 16 23 Total regulatory assets $ 527 $ 718 $ 411 $ 924 (a) Includes the fair value of certain long-term PPAs used to meet energy capacity requirements and valuation adjustments on natural gas commodity purchases. (b) Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions. (c) Includes amounts recorded for future recovery of AROs, less amounts recovered through nuclear decommissioning accruals and gains from decommissioning investments.
Regulatory Liabilities	Components of regulatory liabilities: (Millions of Dollars) See Note(s) Remaining Amortization Period Dec. 31, 2021 Dec. 31, 2020 Regulatory Liabilities Current Noncurrent Current Noncurrent Deferred income tax adjustments and TCJA refunds (a) 7 Various $ 9 $ 1,256 $ 9 $ 1,326 Plant removal costs 1, 10 Various — 613 — 544 Renewable resources and environmental initiatives Various 1 10 5 — ITC deferrals 1 Various — 7 — 8 Contract valuation adjustments (b) 1, 8 Less than one year 29 — 12 — DOE Settlement Less than one year 14 — 11 — Deferred natural gas and electric energy/fuel costs Less than one year 14 — 8 — Other Various 50 41 78 18 Total regulatory liabilities (c) $ 117 $ 1,927 $ 123 $ 1,896 (a) Includes the revaluation of recoverable/regulated plant accumulated deferred income taxes and revaluation impact of non-plant accumulated deferred income taxes due to the TCJA. (b) Includes the fair value of certain long-term PPAs used to meet energy capacity requirements and valuation adjustments on natural gas commodity purchases. (c) Revenue subject to refund of $15 million and $17 million for 2021 and 2020, respectively, is included in other current liabilities.

Borrowings and Other Financin_2

Borrowings and Other Financing Instruments (Tables)	12 Months Ended
	Dec. 31, 2021
Debt Disclosure [Abstract]
Money Pool [Table Text Block]	Money pool borrowings: (Millions of Dollars, Except Interest Rates) Three Months Ended Dec. 31, 2021 Year Ended Dec. 31 2021 2020 2019 Borrowing limit $ 250 $ 250 $ 250 $ 250 Amount outstanding at period end — — — — Average amount outstanding — 6 3 32 Maximum amount outstanding — 236 116 250 Weighted average interest rate, computed on a daily basis N/A 0.07 % 1.53 % 2.05 % 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, 2021 Year Ended Dec. 31 2021 2020 2019 Borrowing limit $ 500 $ 500 $ 500 $ 500 Amount outstanding at period end — — 179 30 Average amount outstanding — 26 10 71 Maximum amount outstanding 13 317 179 317 Weighted average interest rate, computed on a daily basis 0.15 % 0.18 % 1.25 % 2.59 % Weighted average interest rate at end of period N/A N/A 0.18 2.05
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) 2021 2020 47 % 47 % $ 100 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, 2021 (in millions of dollars): Credit Facility (a) Drawn (b) Available $ 500 $ 9 $ 491 (a) This credit facility matures in June 2024. (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 2021 2020 First mortgage bonds 2.15 % Aug. 15, 2022 $ 300 $ 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 — 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 (b) 2.60 June 1, 2051 700 700 First mortgage bonds (a) 3.20 April 1, 2052 425 — Other long-term debt 3 — Unamortized discount (44) (42) Unamortized debt issuance cost (62) (54) Current maturities (300) — Total long-term debt $ 6,447 $ 5,904 (a) 2021 financing.	[4],[5]
Schedule of Maturities of Long-term Debt	Maturities of long-term debt are as follows: (Millions of Dollars) 2022 $ 300 2023 400 2024 — 2025 250 2026 —
Dividend Payment Restrictions	Requirements and actuals as of Dec. 31, 2021: Equity to Total Equity to Total Capitalization Ratio Actual Low High 2021 47.2 % 57.6 % 52.9 % Unrestricted Retained Earnings Total Capitalization Limit on Total Capitalization $ 1,558 million $ 14,321 million $ 15,332 million
[1]	(b) 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]	2020 financing.
[5]	2021 financing.

Revenues Revenues (Tables)

Revenues Revenues (Tables)	12 Months Ended
	Dec. 31, 2021
Revenue from Contract with Customer [Abstract]
Disaggregation of Revenue	NSP-Minnesota’s operating revenues consisted of the following: 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 Year Ended Dec. 31, 2019 (Millions of Dollars) Electric Natural Gas All Other Total Major revenue types Revenue from contracts with customers: Residential $ 1,280 $ 303 $ 30 $ 1,613 C&I 2,054 229 — 2,283 Other 33 — 5 38 Total retail 3,367 532 35 3,934 Wholesale 210 — — 210 Transmission 216 — — 216 Interchange 459 — — 459 Other 12 9 — 21 Total revenue from contracts with customers 4,264 541 35 4,840 Alternative revenue and other 242 30 — 272 Total revenues $ 4,506 $ 571 $ 35 $ 5,112

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2021
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 December 2022 2018 September 2022
Reconciliation of Unrecognized Tax Benefits	Unrecognized tax benefits - permanent vs temporary: (Millions of Dollars) Dec. 31, 2021 Dec. 31, 2020 Unrecognized tax benefit — Permanent tax positions $ 23 $ 21 Unrecognized tax benefit — Temporary tax positions 3 3 Total unrecognized tax benefit $ 26 $ 24 Changes in unrecognized tax benefits: (Millions of Dollars) 2021 2020 2019 Balance at Jan. 1 $ 24 $ 20 $ 17 Additions based on tax positions related to the current year 2 2 3 Reductions based on tax positions related to the current year — — (1) Additions for tax positions of prior years — 16 1 Reductions for tax positions of prior years — (14) — Balance at Dec. 31 $ 26 $ 24 $ 20
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, 2021 Dec. 31, 2020 NOL and tax credit carryforwards $ (13) $ (11)
Interest Payable related to Unrecognized Tax Benefits	Interest payable related to unrecognized tax benefits: (Millions of Dollars) 2021 2020 2019 Payable for interest related to unrecognized tax benefits at Jan. 1 $ (2) $ (2) $ (1) Interest expense related to unrecognized tax benefits — — (1) Payable for interest related to unrecognized tax benefits at Dec. 31 $ (2) $ (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) 2021 2020 Federal NOL carryforward $ 77 $ — Federal tax credit carryforwards 704 543 State NOL carryforwards 344 151 Valuation allowances for state NOL carryforwards (1) (1) State tax credit carryforwards, net of federal detriment (a) 78 71 Valuation allowances for state credit carryforwards, net of federal benefit (b) (64) (59) (a) State tax credit carryforwards are net of federal detriment of $21 million and $19 million as of Dec. 31, 2021 and 2020, respectively. (b) Valuation allowances for state tax credit carryforwards were net of federal benefit of $17 million and $16 million as of Dec. 31, 2021 and 2020, respectively.
Schedule of Effective Income Tax Rate Reconciliation	Total income tax expense from operations differs f rom 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: 2021 2020 2019 Federal statutory rate 21.0 % 21.0 % 21.0 % State income tax on pretax income, net of federal tax effect 7.0 7.0 7.1 Increases (decreases) in tax from: Wind PTCs (27.8) (19.3) (11.8) Plant regulatory differences (a) (8.1) (7.2) (7.4) Other tax credits, net NOL & tax credit allowances (1.4) (1.2) (1.5) Change in unrecognized tax benefits 0.5 1.0 0.5 NOL Carryback — (2.1) — Other, net 0.2 (0.2) 0.1 Effective income tax rate (8.6) % (1.0) % 8.0 %
Schedule of Components of Income Tax Expense (Benefit)	Components of income tax expense for years ended Dec. 31: (Millions of Dollars) 2021 2020 2019 Current federal tax (benefit) expense $ (10) $ 41 $ 80 Current state tax (benefit) expense (1) 12 8 Current change in unrecognized tax expense (benefit) 1 9 (1) Deferred federal tax benefit (87) (102) (86) Deferred state tax expense 49 38 43 Deferred change in unrecognized tax expense (benefit) 2 (3) 4 Deferred ITCs (2) (1) (1) Total income tax (benefit) expense $ (48) $ (6) $ 47 Components of deferred income tax expense as of Dec. 31: (Millions of Dollars) 2021 2020 2019 Deferred tax expense excluding items below $ 109 $ 61 97 Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities (145) (127) (135) Tax expense allocated to other comprehensive income, adoption of ASC Topic 326, and other — (1) (1) Deferred tax benefit $ (36) $ (67) $ (39)
Schedule of Deferred Tax Assets and Liabilities	Components of the net deferred tax liability as of Dec. 31: (Millions of Dollars) 2021 2020 (a) Deferred tax liabilities: Differences between book and tax bases of property $ 2,679 $ 2,482 Regulatory assets 260 270 Operating lease assets 123 147 Deferred fuel costs 92 7 Pension expense 73 72 Other 13 7 Total deferred tax liabilities $ 3,240 $ 2,985 Deferred tax assets: Tax credit carryforward $ 782 $ 614 Regulatory Liabilities 325 349 Operating lease liabilities 123 147 NOL and tax credit valuation allowances (64) (59) Other employee benefits 32 38 NOL carryforward 43 12 Deferred ITCs 5 5 Other 45 39 Total deferred tax assets $ 1,291 $ 1,145 Net deferred tax liability $ 1,949 $ 1,840 (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, 2021
Fair Value Disclosures [Abstract]
Fair Value Disclosures [Text Block]	Fair Value Measurements Accounting guidance for fair value measurements and disclosures provides a single definition of fair value and requires disclosures about assets and liabilities measured at fair value. A hierarchical framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value is established by this guidance. • 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 highly liquid and actively traded instruments with quoted prices. • Level 2 — Pricing inputs are other than quoted 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 are those valued with models requiring significant management judgment or estimation. Cash equivalents — The fair values of cash equivalents are generally based on cost plus accrued interest; money market funds are measured using quoted NAV. 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 fund investments 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’ investments may be redeemed with proper notice, however, 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 — The fair values of interest rate derivatives are based on broker quotes that utilize current market interest rate forecasts. Commodity derivatives — The methods used to measure the fair value of commodity derivative forwards and options utilize forward prices and volatilities, as well as pricing adjustments for specific delivery locations, and are generally assigned a Level 2 classification. When contractual settlements relate to inactive delivery locations or extend to periods beyond those readily observable on active exchanges or quoted by brokers, the significance of the use of less observable forecasts of forward prices and volatilities 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 value of an FTR is derived from, and designed to offset, the cost 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 an FTR. If forecasted costs of electric transmission congestion increase or decrease for a given FTR path, the value of that particular FTR instrument will likewise increase or decrease. Given the limited observability of certain inputs to the value of FTRs between auction processes, including expected plant operating schedules and retail and wholesale demand, fair value measurements for FTRs have been assigned a Level 3. Non-trading monthly FTR settlements are included in fuel and purchased energy cost recovery mechanisms and therefore changes in the fair value of the yet to be settled portions of most FTRs are deferred as a regulatory asset or liability. Given this regulatory treatment and the limited magnitude of NSP-Minnesota’s FTRs relative to its electric utility operations, the numerous unobservable quantitative inputs pertinent to the value of FTRs are immaterial to the consolidated financial statements of NSP-Minnesota. 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 $1.3 billion and $981 million as of Dec. 31, 2021 and 2020, respectively, and unrealized losses were $7 million and $5 million as of Dec. 31, 2021 and 2020, respectively. Non-derivative instruments with recurring fair value measurements in the nuclear decommissioning fund: 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 sheet, which also includes $52 million of rabbi trust assets and miscellaneous investments. Dec. 31, 2020 Fair Value (Millions of Dollars) Cost Level 1 Level 2 Level 3 NAV Total Nuclear decommissioning fund (a) Cash equivalents $ 40 $ 40 $ — $ — $ — $ 40 Commingled funds 787 — — — 1,041 1,041 Debt securities 528 — 572 13 — 585 Equity securities 446 1,109 2 — — 1,111 Total $ 1,801 $ 1,149 $ 574 $ 13 $ 1,041 $ 2,777 (a) Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $53 million of rabbi trust assets and miscellaneous investments. For the years ended Dec. 31, 2021 and 2020, 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, 2021: Final Contractual Maturity (Millions of Dollars) Due in 1 year or Less Due in 1 to 5 Years Due in 5 to 10 Years Due after 10 Years Total Debt securities $ 4 $ 149 $ 208 $ 314 $ 675 Rabbi Trusts NSP-Minnesota has established a rabbi trust to provide partial funding for future deferred compensation plan distributions. Cost and fair value of assets held in rabbi trusts: Dec. 31, 2021 Fair Value (Millions of Dollars) Cost Level 1 Level 2 Level 3 Total Rabbi Trusts (a) Mutual funds $ 10 $ 13 $ — $ — $ 13 Total $ 10 $ 13 $ — $ — $ 13 (a) Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet. Dec. 31, 2020 Fair Value (Millions of Dollars) Cost Level 1 Level 2 Level 3 Total Rabbi Trusts (a) Cash equivalents $ 1 $ 1 $ — $ — $ 1 Mutual funds 14 16 — — 16 Total $ 15 $ 17 $ — $ — $ 17 (a) Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet. Derivative Instruments Fair Value Measurements 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, utility commodity prices and vehicle fuel prices. Interest Rate Derivatives — NSP-Minnesota enters into various instruments that effectively fix the yield or price on a specified benchmark interest rate for an anticipated debt issuance for a specific period. These derivative instruments are generally designated as cash flow hedges for accounting purposes, with changes in fair value prior to settlement recorded as other comprehensive income. As of Dec. 31, 2021, accumulated other comprehensive loss related to settled interest rate derivatives included $1 million of net losses expected to be reclassified into earnings during the next 12 months as the hedged interest rate transactions impact earnings. As of Dec. 31, 2021, NSP-Minnesota had no unsettled interest rate derivatives. Wholesale and Commodity Trading Risk — 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 activities governed by this policy. 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, as well as for trading purposes. This could include the purchase or sale of energy or energy-related products, natural gas to generate electric energy, natural gas for resale, FTRs, vehicle fuel, and weather derivatives. As of Dec. 31, 2021, NSP-Minnesota had no commodity contracts designated as cash flow hedges. NSP-Minnesota may enter into derivative instruments that mitigate commodity price risk on behalf of electric and natural gas customers, but may not be 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. NSP-Minnesota enters into commodity derivative instruments for trading purposes not directly related to commodity price risks associated with serving its electric and natural gas customers. Changes in the fair value of these commodity derivatives are recorded in electric operating revenues, net of amounts credited to customers under margin-sharing mechanisms. Gross notional amounts of commodity forwards, options and FTRs: (Amounts in Millions) (a)(b) Dec. 31, 2021 Dec. 31, 2020 MWh of electricity 57 65 MMBtu of natural gas 85 83 (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, 2021, eight of NSP-Minnesota’s 10 most significant counterparties for these activities, comprising $33 million or 63% of this credit exposure, had investment grade credit ratings from S&P, Moody’s or Fitch Ratings. One of the 10 most significant counterparties, comprising $17 million or 34% of this credit exposure, was not rated by these external agencies, but based on NSP-Minnesota’s internal analysis, had credit quality consistent with investment grade. One of these significant counterparties, comprising an immaterial amount or less than 1% of this credit exposure, had credit quality less than investment grade, based on internal analysis. Six of these significant counterparties are municipal or cooperative electric entities, RTOs or other utilities. Qualifying Cash Flow Hedges — Financial impact of qualifying interest rate and vehicle fuel 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: (Millions of Dollars) 2021 2020 2019 Accumulated other comprehensive loss related to cash flow hedges at Jan. 1 $ (19) $ (20) $ (20) After-tax net realized losses on derivative transactions reclassified into earnings 2 1 — Accumulated other comprehensive loss related to cash flow hedges at Dec. 31 $ (17) $ (19) $ (20) Impact of derivative activity: Pre-Tax Fair Value (Millions of Dollars) Accumulated Other Comprehensive Loss Regulatory (Assets) and Liabilities 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 $ — $ — Year Ended Dec. 31, 2019 Other derivative instruments Electric commodity $ — $ 2 Natural gas commodity — (3) Total $ — $ (1) Pre-Tax (Gains) Losses Pre-Tax Gains (Losses) (Millions of Dollars) Accumulated Other Comprehensive Loss Regulatory 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) Total $ — $ (2) $ 45 Pre-Tax (Gains) Losses Pre-Tax Gains (Losses) (Millions of Dollars) Accumulated Other Comprehensive Loss Regulatory 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) Total $ — $ (1) $ (9) Pre-Tax (Gains) Losses Pre-Tax Gains (Losses) (Millions of Dollars) Accumulated Other Comprehensive Loss Regulatory Year Ended Dec. 31, 2019 Other derivative instruments Electric commodity $ — $ 1 (c) $ — Natural gas commodity — 1 (d) (3) (d) Total $ — $ 2 $ (3) (a) 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. (b) Amounts are recorded to cost of natural gas sold and transported. These derivative settlement gains and losses are shared with natural gas customers through purchased natural gas cost-recovery mechanisms and reclassified out of income as regulatory assets and liabilities, as appropriate. (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. (d) Amounts are recorded to cost of natural gas sold and transported. These derivative settlement gains and losses are shared with natural gas customers through purchased natural gas cost-recovery mechanisms and reclassified out of income as regulatory assets and liabilities, as appropriate. NSP-Minnesota had no derivative instruments designated as fair value hedges during the years ended Dec. 31, 2021, 2020 and 2019. Credit Related Contingent Features — Contract provisions for derivative instruments that NSP-Minnesota enters into, including those accounted for as normal purchase-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 NSP-Minnesota’s credit ratings are downgraded below its investment grade credit rating by any of the major credit rating agencies. As of Dec. 31, 2021 and 2020, there were $3 million and $4 million derivative instruments in a liability position 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 the other financing arrangements related to payment terms or other covenants. As of Dec. 31, 2021 and 2020, there were approximately $48 million and $14 million of derivative instruments in a liability position with such underlying contract provisions, respectively. Provisions allow counterparties to seek performance assurance, including cash collateral, in the event that NSP-Minnesota’s ability to fulfill its contractual obligations is reasonably expected to be impaired. NSP-Minnesota had no collateral posted related to adequate assurance clauses in derivative contracts as of Dec. 31, 2021 and 2020. Recurring Fair Value Measurements — NSP-Minnesota’s derivative assets and liabilities measured at fair value on a recurring basis were as follows: Dec. 31, 2021 Dec. 31, 2020 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 $ 9 $ 40 $ 22 $ 71 $ (53) $ 18 $ 1 $ 26 $ — $ 27 $ (25) $ 2 Electric commodity — — 30 30 (1) 29 — — 13 13 (1) 12 Natural gas commodity — 6 — 6 — 6 — 3 — 3 — 3 Total current derivative assets $ 9 $ 46 $ 52 $ 107 $ (54) $ 53 $ 1 $ 29 $ 13 $ 43 $ (26) $ 17 Noncurrent derivative assets Other derivative instruments: Commodity trading $ 6 $ 34 $ 35 $ 75 $ (42) $ 33 $ 7 $ 39 $ — $ 46 $ (41) $ 5 Total noncurrent derivative assets $ 6 $ 34 $ 35 $ 75 $ (42) $ 33 $ 7 $ 39 $ — $ 46 $ (41) $ 5 Dec. 31, 2021 Dec. 31, 2020 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 $ 13 $ 58 $ 4 $ 75 $ (58) $ 17 $ 3 $ 18 $ 10 $ 31 $ (25) $ 6 Electric commodity — — 1 1 (1) — — — 1 1 (1) — Natural gas commodity — 4 — 4 — 4 — 2 — 2 — 2 Total current derivative liabilities $ 13 $ 62 $ 5 $ 80 $ (59) 21 $ 3 $ 20 $ 11 $ 34 $ (26) 8 PPAs (b) 14 14 Current derivative instruments $ 35 $ 22 Noncurrent derivative liabilities Other derivative instruments: Commodity trading $ 15 $ 48 $ 26 $ 89 $ (53) $ 36 $ 2 $ 35 $ 13 $ 50 $ (27) $ 23 Total noncurrent derivative liabilities $ 15 $ 48 $ 26 $ 89 $ (53) 36 $ 2 $ 35 $ 13 $ 50 $ (27) 23 PPAs (b) 35 48 Noncurrent derivative instruments $ 71 $ 71 (a) NSP-Minnesota nets derivative instruments and related collateral on its consolidated balance sheets when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Dec. 31, 2021 and 2020. At Dec. 31, 2021 derivative assets and liabilities include no obligations to return cash collateral. At Dec. 31, 2020 derivative assets and liabilities include $15 million of obligations to return cash collateral. At Dec. 31, 2021 and 2020, derivative assets and liabilities include the rights to reclaim cash collateral of $16 million and $1 million, respectively. The counterparty netting excludes settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements. (b) During 2006, Xcel Energy qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities. Changes in Level 3 commodity derivatives for the years ended Dec. 31, 2021, 2020 and 2019: Year Ended Dec. 31 (Millions of Dollars) 2021 2020 2019 Balance at Jan. 1 $ (11) $ 5 $ 14 Purchases 54 28 17 Settlements (82) (49) (28) Net transactions recorded during the period: Gains (losses) recognized in earnings (a) 72 (8) 3 Net gains (losses) recognized as regulatory assets and liabilities 23 13 (1) Balance at Dec. 31 $ 56 $ (11) $ 5 (a) Level 3 losses and gains recognized in earnings are subject to offsetting gains and losses of derivative instruments categorized as levels 1 and 2 in the income statement. Fair Value of Long-Term Debt As of Dec. 31, other financial instruments for which the carrying amount did not equal fair value: 2021 2020 (Millions of Dollars) Carrying Amount Fair Value Carrying Amount Fair Value Long-term debt, including current portion $ 6,747 $ 7,761 $ 5,904 $ 7,391
Cost and Fair Value of Nuclear Decommissioning Fund Investments	Non-derivative instruments with recurring fair value measurements in the nuclear decommissioning fund: 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 sheet, which also includes $52 million of rabbi trust assets and miscellaneous investments. Dec. 31, 2020 Fair Value (Millions of Dollars) Cost Level 1 Level 2 Level 3 NAV Total Nuclear decommissioning fund (a) Cash equivalents $ 40 $ 40 $ — $ — $ — $ 40 Commingled funds 787 — — — 1,041 1,041 Debt securities 528 — 572 13 — 585 Equity securities 446 1,109 2 — — 1,111 Total $ 1,801 $ 1,149 $ 574 $ 13 $ 1,041 $ 2,777 (a) Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $53 million of rabbi trust assets and 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, 2021: Final Contractual Maturity (Millions of Dollars) Due in 1 year or Less Due in 1 to 5 Years Due in 5 to 10 Years Due after 10 Years Total Debt securities $ 4 $ 149 $ 208 $ 314 $ 675
Rabbi Trust Securities Amortized Cost and Fair Value Measured on Recurrring Basis [Table Text Block]	Cost and fair value of assets held in rabbi trusts: Dec. 31, 2021 Fair Value (Millions of Dollars) Cost Level 1 Level 2 Level 3 Total Rabbi Trusts (a) Mutual funds $ 10 $ 13 $ — $ — $ 13 Total $ 10 $ 13 $ — $ — $ 13 (a) Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet. Dec. 31, 2020 Fair Value (Millions of Dollars) Cost Level 1 Level 2 Level 3 Total Rabbi Trusts (a) Cash equivalents $ 1 $ 1 $ — $ — $ 1 Mutual funds 14 16 — — 16 Total $ 15 $ 17 $ — $ — $ 17 (a) Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet.
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, 2021 Dec. 31, 2020 MWh of electricity 57 65 MMBtu of natural gas 85 83 (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.
Financial Impact of Qualifying Cash Flow Hedges on Accumulated Other Comprehensive Loss	(Millions of Dollars) 2021 2020 2019 Accumulated other comprehensive loss related to cash flow hedges at Jan. 1 $ (19) $ (20) $ (20) After-tax net realized losses on derivative transactions reclassified into earnings 2 1 — Accumulated other comprehensive loss related to cash flow hedges at Dec. 31 $ (17) $ (19) $ (20)
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, 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 $ — $ — Year Ended Dec. 31, 2019 Other derivative instruments Electric commodity $ — $ 2 Natural gas commodity — (3) Total $ — $ (1) Pre-Tax (Gains) Losses Pre-Tax Gains (Losses) (Millions of Dollars) Accumulated Other Comprehensive Loss Regulatory 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) Total $ — $ (2) $ 45 Pre-Tax (Gains) Losses Pre-Tax Gains (Losses) (Millions of Dollars) Accumulated Other Comprehensive Loss Regulatory 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) Total $ — $ (1) $ (9) Pre-Tax (Gains) Losses Pre-Tax Gains (Losses) (Millions of Dollars) Accumulated Other Comprehensive Loss Regulatory Year Ended Dec. 31, 2019 Other derivative instruments Electric commodity $ — $ 1 (c) $ — Natural gas commodity — 1 (d) (3) (d) Total $ — $ 2 $ (3) (a) 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. (b) Amounts are recorded to cost of natural gas sold and transported. These derivative settlement gains and losses are shared with natural gas customers through purchased natural gas cost-recovery mechanisms and reclassified out of income as regulatory assets and liabilities, as appropriate. (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.
Derivative Assets and Liabilities Measured at Fair Value on a Recurring Basis by Hierarchy Level	NSP-Minnesota’s derivative assets and liabilities measured at fair value on a recurring basis were as follows: Dec. 31, 2021 Dec. 31, 2020 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 $ 9 $ 40 $ 22 $ 71 $ (53) $ 18 $ 1 $ 26 $ — $ 27 $ (25) $ 2 Electric commodity — — 30 30 (1) 29 — — 13 13 (1) 12 Natural gas commodity — 6 — 6 — 6 — 3 — 3 — 3 Total current derivative assets $ 9 $ 46 $ 52 $ 107 $ (54) $ 53 $ 1 $ 29 $ 13 $ 43 $ (26) $ 17 Noncurrent derivative assets Other derivative instruments: Commodity trading $ 6 $ 34 $ 35 $ 75 $ (42) $ 33 $ 7 $ 39 $ — $ 46 $ (41) $ 5 Total noncurrent derivative assets $ 6 $ 34 $ 35 $ 75 $ (42) $ 33 $ 7 $ 39 $ — $ 46 $ (41) $ 5 Dec. 31, 2021 Dec. 31, 2020 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 $ 13 $ 58 $ 4 $ 75 $ (58) $ 17 $ 3 $ 18 $ 10 $ 31 $ (25) $ 6 Electric commodity — — 1 1 (1) — — — 1 1 (1) — Natural gas commodity — 4 — 4 — 4 — 2 — 2 — 2 Total current derivative liabilities $ 13 $ 62 $ 5 $ 80 $ (59) 21 $ 3 $ 20 $ 11 $ 34 $ (26) 8 PPAs (b) 14 14 Current derivative instruments $ 35 $ 22 Noncurrent derivative liabilities Other derivative instruments: Commodity trading $ 15 $ 48 $ 26 $ 89 $ (53) $ 36 $ 2 $ 35 $ 13 $ 50 $ (27) $ 23 Total noncurrent derivative liabilities $ 15 $ 48 $ 26 $ 89 $ (53) 36 $ 2 $ 35 $ 13 $ 50 $ (27) 23 PPAs (b) 35 48 Noncurrent derivative instruments $ 71 $ 71 (a) NSP-Minnesota nets derivative instruments and related collateral on its consolidated balance sheets when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Dec. 31, 2021 and 2020. At Dec. 31, 2021 derivative assets and liabilities include no obligations to return cash collateral. At Dec. 31, 2020 derivative assets and liabilities include $15 million of obligations to return cash collateral. At Dec. 31, 2021 and 2020, derivative assets and liabilities include the rights to reclaim cash collateral of $16 million and $1 million, respectively. The counterparty netting excludes settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements. (b) During 2006, Xcel Energy qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.
Changes in Level 3 Commodity Derivatives	Changes in Level 3 commodity derivatives for the years ended Dec. 31, 2021, 2020 and 2019: Year Ended Dec. 31 (Millions of Dollars) 2021 2020 2019 Balance at Jan. 1 $ (11) $ 5 $ 14 Purchases 54 28 17 Settlements (82) (49) (28) Net transactions recorded during the period: Gains (losses) recognized in earnings (a) 72 (8) 3 Net gains (losses) recognized as regulatory assets and liabilities 23 13 (1) Balance at Dec. 31 $ 56 $ (11) $ 5 (a) Level 3 losses and gains recognized in earnings are subject to offsetting gains and losses of derivative instruments categorized as levels 1 and 2 in the income statement.
Carrying Amount and Fair Value of Long-term Debt	2021 2020 (Millions of Dollars) Carrying Amount Fair Value Carrying Amount Fair Value Long-term debt, including current portion $ 6,747 $ 7,761 $ 5,904 $ 7,391

Benefit Plans and Other Postr_2

Benefit Plans and Other Postretirement Benefits (Tables)	12 Months Ended
	Dec. 31, 2021
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) 2021 2020 2021 2020 Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost: Net loss $ 307 $ 414 $ 31 $ 37 Prior service credit — — (4) (6) Total $ 307 $ 414 $ 27 $ 31 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 $ 25 $ 29 $ — $ — Noncurrent regulatory assets 282 385 25 29 Deferred income taxes — — 1 1 Net-of-tax accumulated other comprehensive income — — 1 1 Total $ 307 $ 414 $ 27 $ 31 Measurement date Dec 31, 2021 Dec 31, 2020 Dec 31, 2021 Dec 31, 2020
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 Expected Net Projected 2022 $ 118 $ 6 $ — $ 6 2023 72 6 — 6 2024 68 5 — 5 2025 67 5 — 5 2026 64 5 — 5 2027-2031 292 18 — 18
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, 2021 (a) Dec. 31, 2020 (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 $ 31 $ — $ — $ — $ 31 $ 52 $ — $ — $ — $ 52 Commingled funds 304 — — 274 578 369 — — 284 653 Debt securities — 219 1 — 220 — 167 1 — 168 Equity securities 16 — — — 16 20 — — — 20 Other — 1 — 7 8 3 1 — — 4 Total $ 351 $ 220 $ 1 $ 281 $ 853 $ 444 $ 168 $ 1 $ 284 $ 897 (a) See Note 8 for further information on 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, 2021 (a) Dec. 31, 2020 (a) (Millions of Dollars) Level 1 Level 2 Level 3 Measured at NAV Total Level 1 Level 2 Level 3 Measured at NAV Total Commingled funds $ — $ — $ — $ 1 $ 1 $ — $ — $ — $ — $ — Debt securities — 2 — — 2 — 2 — — 2 Total $ — $ 2 $ — $ 1 $ 3 $ — $ 2 $ — $ — $ 2
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) 2021 2020 2021 2020 Change in Benefit Obligation: Obligation at Jan. 1 $ 989 $ 942 $ 73 $ 76 Service cost 30 27 — — Interest cost 25 31 2 2 Plan amendments 1 — — — Actuarial (gain) loss (28) 84 (5) 2 Benefit payments (140) (95) (6) (7) Obligation at Dec. 31 $ 877 $ 989 $ 64 $ 73 Change in Fair Value of Plan Assets: Fair value of plan assets at Jan. 1 $ 897 $ 815 $ 2 $ 3 Actual return on plan assets 62 133 — — Employer contributions 34 44 7 6 Benefit payments (140) (95) (6) (7) Fair value of plan assets at Dec. 31 $ 853 $ 897 $ 3 $ 2 Funded status of plans at Dec. 31 $ (24) $ (92) $ (61) $ (71) Amounts recognized in the Consolidated Balance Sheet at Dec. 31: Current liabilities $ — $ — $ (3) $ (5) Noncurrent liabilities (24) (92) (58) (66) Net amounts recognized $ (24) $ (92) $ (61) $ (71) Pension Benefits Postretirement Benefits Significant Assumptions Used to Measure Benefit Obligations: 2021 2020 2021 2020 Discount rate for year-end valuation 3.08 % 2.71 % 3.09 % 2.65 % Expected average long-term increase in compensation level 3.75 % 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 5.30 % 5.50 % Health care costs trend rate — initial: Post-65 N/A N/A 4.90 % 5.00 % 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 4 5
Components of Net Periodic Benefit Costs	Pension Benefits Postretirement Benefits (Millions of Dollars) 2021 2020 2019 2021 2020 2019 Service cost $ 30 $ 27 $ 25 $ — $ — $ — Interest cost 25 31 37 2 2 3 Expected return on plan assets (52) (55) (54) — — — Amortization of prior service cost — — — (3) (3) (3) Amortization of net loss 34 33 30 2 1 2 Settlement charge (a) 35 — — — — — Net periodic pension cost 72 36 38 1 — 2 Effects of regulation (44) (4) (5) — — — Net benefit cost recognized for financial reporting $ 28 $ 32 $ 33 $ 1 $ — $ 2 Significant Assumptions Used to Measure Costs: Discount rate 2.71 % 3.49 % 4.31 % 2.65 % 3.47 % 4.32 % 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 7.10 7.10 4.10 4.50 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 2021, as a result of lump-sum distributions during the 2021 plan year, NSP-Minnesota recorded a total pension settlement charge of $35 million in 2021, which was not recognized due to the effects of regulation. There were no settlement charges recorded to the qualified pension plans in 2020 and 2019.
Postretirement Benefits Plan
Benefit Plans and Other Postretirement Benefits [Abstract]
Target Asset Allocations and Plan Assets Measured at Fair Value	Target asset allocations: Pension Benefits Postretirement Benefits 2021 2020 2021 2020 Domestic and international equity securities 33 % 35 % 15 % 15 % Long-duration fixed income and interest rate swap securities 37 35 — — Short-to-intermediate fixed income securities 11 13 71 72 Alternative investments 17 15 8 9 Cash 2 2 6 4 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, 2021
Commitments and Contingencies Disclosure [Abstract]
Asset Retirement Obligations	NSP-Minnesota’s AROs were as follows: 2021 (Millions Jan. 1, 2021 Amounts Incurred (a) Accretion Cash Flow Revisions (b) Dec. 31, 2021 (c) Electric Nuclear $ 1,957 $ — $ 99 $ — $ 2,056 Wind 270 101 13 — 384 Steam and other production 67 6 2 (2) 73 Distribution 16 — — — 16 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. (c) There were no ARO amounts settled in 2021. 2020 (Millions Jan. 1, 2020 Amounts Incurred (a) Amounts Settled (b) Accretion Cash Flow Revisions (c) Dec. 31, 2020 Electric Nuclear $ 2,068 $ — $ — $ 105 $ (216) $ 1,957 Wind 113 90 — 7 60 270 Steam and other production 47 — (3) 2 21 67 Distribution 15 — — 1 — 16 Miscellaneous — — — — — — Natural gas Transmission and distribution 36 — — 2 1 39 Common Miscellaneous 1 — — — — 1 Total liability $ 2,280 $ 90 $ (3) $ 117 $ (134) $ 2,350 (a) Amounts incurred relate to the wind farms placed in service in 2020 (Blazing Star 1, Crowned Ridge, Jeffers and Community Wind North). (b) Amounts settled related to closure of certain ash containment facilities. (c) In 2020, AROs were revised for changes in timing and estimates of cash flows. Revisions in the nuclear AROs were driven by reductions in spent fuel cooling time requirements in the nuclear triennial filing coupled with decreasing interest rates. Changes in wind AROs were driven by new dismantling studies. Revisions in steam and other production AROs primarily related to changes in cost estimates for remediation of ash containment facilities.
Funded Status of Nuclear Decommissioning Obligation	The following amounts were prepared on a regulatory basis and not directly recorded in the financial statements as an ARO. Regulatory Basis (Millions of Dollars) 2021 2020 Estimated decommissioning cost obligation from most recently $ 3,012 $ 3,012 Effect of escalating costs 1,006 844 Estimated decommissioning cost obligation (in current dollars) 4,018 3,856 Effect of escalating costs to payment date 7,187 7,349 Estimated future decommissioning costs (undiscounted) 11,205 11,205 Effect of discounting obligation (using average risk-free interest rate of 1.96% and 1.64% for 2021 and 2020, respectively) (4,651) (4,181) Discounted decommissioning cost obligation $ 6,554 $ 7,024 Assets held in external decommissioning trust $ 3,256 $ 2,777 Underfunding of external decommissioning fund compared to 3,298 4,247
Reconciliation of discounted decommissioning cost obligation - regulated basis to the ARO recordfed in	Reconciliation of the discounted decommissioning cost obligation - regulated basis to the ARO recorded in accordance with GAAP: (Millions of Dollars) 2021 2020 Discounted decommissioning cost obligation - regulated basis $ 6,554 $ 7,024 Differences in discount rate and market risk premium (2,209) (2,628) O&M costs not included for GAAP (1,584) (1,734) ARO differences between 2020 and 2014 cost studies (705) (705) Nuclear production decommissioning ARO - GAAP $ 2,056 $ 1,957
Nuclear Decommissioning Expenses Recognized as Result of Regulation	Decommissioning expenses recognized as a result of regulation: (Millions of Dollars) 2021 2020 2019 Annual decommissioning recorded as depreciation expense: (a) (b) $ 22 $ 20 $ 20 (a) Decommissioning expense does not include depreciation of the capitalized nuclear asset retirement costs.
Assets and Liabilities, Lessee [Table Text Block]	Operating lease ROU assets: (Millions of Dollars) Dec. 31, 2021 Dec. 31, 2020 PPAs $ 556 $ 558 Other 74 74 Gross operating lease ROU assets 630 632 Accumulated amortization (222) (144) Net operating lease ROU assets $ 408 $ 488
Lease, Cost [Table Text Block]	Components of lease expense: (Millions of Dollars) 2021 2020 2019 Operating leases PPA capacity payments $ 96 $ 89 $ 76 Other operating leases (a) 8 8 9 Total operating lease expense (b) $ 104 $ 97 $ 85 (a) Includes short-term lease expense o f $2 million , $2 million and $1 million for 2021, 2020 and 2019, respectively.
Lessee, Operating Lease, Liability, Maturity [Table Text Block]	Commitments under operating leases as of Dec. 31, 2021: (Millions of Dollars) PPA (a) (b) Operating Leases Other Operating Leases Total Leases 2022 $ 96 $ 9 $ 105 2023 98 12 110 2024 100 7 107 2025 80 7 87 2026 40 7 47 Thereafter — 31 31 Total minimum obligation 414 73 487 Interest component of obligation (32) (12) (44) Present value of minimum obligation $ 382 $ 61 443 Less current portion (90) Noncurrent operating lease liabilities $ 353 Weighted-average remaining lease term in years 8.5 (a) Amounts do not include PPAs accounted for as executory contracts and/or contingent payments, such as energy payments on renewable PPAs. (b) PPA operating leases contractually expire at various dates through 2039.
Estimated Minimum Purchases Under Fuel Contracts	Estimated minimum purchases for these contracts as of Dec. 31, 2021: (Millions of Dollars) Coal Nuclear fuel Natural gas Natural gas 2022 $ 219 $ 89 $ 95 $ 128 2023 79 109 — 114 2024 48 82 — 108 2025 1 119 — 98 2026 1 29 — 97 Thereafter 1 309 — 107 Total (a) $ 349 $ 737 $ 95 $ 652 (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, 2021, 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) 2022 $ 60 $ 165 2023 61 169 2024 63 174 2025 26 53 2026 9 10 Thereafter 10 38 Total (b) $ 229 $ 609 (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, 2021
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: 2021 (Millions of Dollars) Gains and Losses on 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: Interest rate derivatives, net of tax of $— 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. 2020 (Millions of Dollars) Gains and Losses on Cash Flow Hedges Defined Benefit Pension and Postretirement Items Total Accumulated other comprehensive loss at Jan. 1 $ (20) $ (3) $ (23) Losses reclassified from net accumulated other comprehensive loss: Interest rate derivatives, net of tax of $— 1 (a) — 1 Net current period other comprehensive income 1 — 1 Accumulated other comprehensive loss at Dec. 31 $ (19) $ (3) $ (22) (a) Included in interest charges.

Segments and Related Informat_2

Segments and Related Information (Tables)	12 Months Ended
	Dec. 31, 2021
Segment Reporting [Abstract]
Results from Operations by Reportable Segment	NSP-Minnesota’s segment information: (Millions of Dollars) 2021 2020 2019 Regulated Electric Operating revenues — external (a) $ 5,094 $ 4,571 $ 4,506 Intersegment revenue 1 1 1 Total revenues $ 5,095 $ 4,572 $ 4,507 Depreciation and amortization 869 773 742 Interest charges and financing costs 240 221 205 Income tax (benefit) expense (53) (14) 36 Net income 566 553 491 Regulated Natural Gas Operating revenues — external (b) $ 623 $ 493 $ 571 Intersegment revenue 1 — 1 Total revenues $ 624 $ 493 $ 572 Depreciation and amortization 56 51 49 Interest charges and financing costs 18 17 16 Income tax expense 6 7 12 Net income 29 30 40 All Other Total revenues $ 39 $ 37 $ 35 Depreciation and amortization 1 1 — Income tax (benefit) expense (1) 1 (1) Net income 11 8 12 Consolidated Total Total revenues (a)(b) $ 5,758 $ 5,102 $ 5,114 Reconciling eliminations (2) (1) (2) Total operating revenues $ 5,756 $ 5,101 $ 5,112 Depreciation and amortization 926 825 791 Interest charges and financing costs 258 238 221 Income tax (benefit) expense (48) (6) 47 Net income 606 591 543 (a) Operating revenues include $501 million, $440 million and $457 million of affiliate electric revenue for the years ended Dec. 31, 2021, 2020 and 2019, respectively. See Note 13 for further information.

Related Party Transactions (Tab

Related Party Transactions (Tables)	12 Months Ended
	Dec. 31, 2021
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) 2021 2020 2019 Operating revenues: Electric $ 501 $ 440 $ 457 Gas 1 1 1 Operating expenses: Purchased power 67 59 61 Transmission expense 121 109 116 Other operating expenses — paid to Xcel Energy Services Inc. 615 584 533 Interest expense — — 1 Accounts receivable and payable with affiliates at Dec. 31: 2021 2020 (Millions of Dollars) Accounts Receivable Accounts Payable Accounts Receivable Accounts Payable NSP-Wisconsin $ 13 $ — $ 6 $ — PSCo 16 — 1 — SPS — 2 — 3 Other subsidiaries of Xcel Energy Inc. — 61 25 63 $ 29 $ 63 $ 32 $ 66

Summarized Quarterly Financia_2

Summarized Quarterly Financial Data (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2021
Quarterly Financial Information Disclosure [Abstract]
Summarized Quarterly Financial Data (Unaudited)	Quarter Ended (Millions of Dollars) March 31, 2021 June 30, 2021 Sept. 30, 2021 Dec. 31, 2021 Operating revenues $ 1,250 $ 1,180 $ 1,388 $ 1,283 Operating income 157 158 314 167 Net income 107 117 246 121 Quarter Ended (Millions of Dollars) March 31, 2020 June 30, 2020 Sept. 30, 2020 Dec. 31, 2020 Operating revenues $ 1,250 $ 1,180 $ 1,388 $ 1,283 Operating income 157 158 314 167 Net income 107 117 246 121

Summary of Significant Accoun_4

Summary of Significant Accounting Policies (Details) - USD ($)	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Property, Plant and Equipment [Abstract]
Depreciation expense expressed as a percentage of average depreciable property	3.70%	3.70%	3.70%
Nuclear Decommissioning [Abstract]
Studies timeframe	$ 3
Cash and Cash Equivalents [Abstract]
cash and cash equivalents	3
Accounts and Financing Receivable, after Allowance for Credit Loss, Current and Noncurrent [Abstract]
Allowance for bad debts	45,000,000	$ 33,000,000
Alternative Revenue Programs [Abstract]
maximum number of months following annual period	24
Public Utilities, Inventory [Line Items]
Public Utilities, Inventory	309,000,000	295,000,000
Supplies
Public Utilities, Inventory [Line Items]
Public Utilities, Inventory	181,000,000	178,000,000
Public Utilities, Inventory, Fuel
Public Utilities, Inventory [Line Items]
Public Utilities, Inventory	81,000,000	90,000,000
Public Utilities, Inventory, Natural Gas
Public Utilities, Inventory [Line Items]
Public Utilities, Inventory	$ 47,000,000	$ 27,000,000

Accounting Pronouncements - Rec

Accounting Pronouncements - Recently Adopted (Details) - USD ($) $ in Millions	Jan. 01, 2020	Dec. 31, 2020
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	$ 1

Property Plant and Equipment (D

Property Plant and Equipment (Details) - USD ($) $ in Millions		Dec. 31, 2021	Dec. 31, 2020
Property, Plant and Equipment [Line Items]
Property, plant and equipment		$ 23,728	$ 22,896
Accumulated depreciation and amortization		7,606	7,898
Property, Plant and Equipment, Net		16,430	15,308
Electric plant
Property, Plant and Equipment [Line Items]
Property, plant and equipment		19,154	18,948
Natural gas plant
Property, Plant and Equipment [Line Items]
Property, plant and equipment		1,864	1,707
Common and other property
Property, Plant and Equipment [Line Items]
Property, plant and equipment		1,007	955
Plant to be Retired [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment	[1]	719	136
CWIP
Property, Plant and Equipment [Line Items]
Property, plant and equipment		984	1,150
Nuclear fuel
Property, Plant and Equipment [Line Items]
Property, plant and equipment		3,081	2,970
Accumulated depreciation and amortization		$ 2,773	$ 2,660
[1]	Includes regulator-approved retirements of Sherco Units 1, 2 and 3 and A.S. King.

Property Plant and Equipment _2

Property Plant and Equipment Property Plant and Equipment Joint Ownership (Details) $ in Millions	Dec. 31, 2021USD ($)
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	$ 1,814	[1]
Accumulated Depreciation	694	[1]
CWIP	7
Electric Generation | Sherco Unit 3
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	620
Accumulated Depreciation	$ 451
Percent Owned	59.00%
Electric Generation | Sherco Common Facilities Units 1, 2 and 3
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	$ 178
Accumulated Depreciation	$ 108
Percent Owned	80.00%
Electric Generation | Sherco Substation
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	$ 5
Accumulated Depreciation	$ 4
Percent Owned	59.00%
Electric Transmission | Grand Meadow
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	$ 11
Accumulated Depreciation	$ 3
Percent Owned	50.00%
Electric Transmission | Huntley Wilmarth
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	$ 48
Accumulated Depreciation	$ 1
Percent Owned	50.00%
Electric Transmission | CapX2020 Transmission
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	$ 952
Accumulated Depreciation	$ 127
Percent Owned	51.00%
[1]	Projects additionally include $7 million in CWIP.

Regulatory Assets and Liabili_3

Regulatory Assets and Liabilities, Regulatory Assets (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2021	Dec. 31, 2020
Regulatory Assets [Line Items]
Regulatory Asset, Current		$ 527	$ 411
Regulatory assets		718	924
Regulatory assets not currently earning a return		691	399
Pension and Retiree Medical Obligations
Regulatory Assets [Line Items]
Regulatory Asset, Current		24	26
Regulatory assets		301	364
Excess deferred taxes - TCJA
Regulatory Assets [Line Items]
Regulatory Asset, Current		10	10
Regulatory assets		113	122
Recoverable Deferred Taxes on AFUDC Recorded in Plant
Regulatory Assets [Line Items]
Regulatory Asset, Current		0	0
Regulatory assets		114	113
Benson purchase power agreement termination and asset purchase
Regulatory Assets [Line Items]
Regulatory Asset, Current		10	10
Regulatory assets		$ 55	65
Regulatory Asset, Amortization Period		8 years
PI extended power update
Regulatory Assets [Line Items]
Regulatory Asset, Current		$ 4	3
Regulatory assets		$ 46	49
Regulatory Asset, Amortization Period		13 years
Contract Valuation Adjustments
Regulatory Assets [Line Items]
Regulatory Asset, Current	[1]	$ 18	16
Regulatory assets	[1]	34	48
Laurentian biomass PPA termination
Regulatory Assets [Line Items]
Regulatory Asset, Current		18	18
Regulatory assets		$ 18	36
Regulatory Asset, Amortization Period		2 years
Purchased Power Agreements
Regulatory Assets [Line Items]
Regulatory Asset, Current		$ 6	4
Regulatory assets		27	32
Sales True-Up and Revenue Decoupling
Regulatory Assets [Line Items]
Regulatory Asset, Current		33	101
Regulatory assets		$ 56	28
Sales True-Up and Revenue Decoupling | Minimum [Member]
Regulatory Assets [Line Items]
Regulatory Asset, Amortization Period		1 year
Sales True-Up and Revenue Decoupling | Maximum [Member]
Regulatory Assets [Line Items]
Regulatory Asset, Amortization Period		2 years
Conservation Programs
Regulatory Assets [Line Items]
Regulatory Asset, Current	[2]	$ 7	14
Regulatory assets	[2]	$ 22	23
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		$ 138	8
Regulatory assets		$ 190	18
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
Regulatory assets		11	12
Nuclear Refueling Outage Costs
Regulatory Assets [Line Items]
Regulatory Asset, Current		37	28
Regulatory assets		$ 16	10
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
Environmental Remediation Costs
Regulatory Assets [Line Items]
Regulatory Asset, Current		$ 0	1
Regulatory assets		5	9
State Commission Adjustments
Regulatory Assets [Line Items]
Regulatory Asset, Current		0	0
Regulatory assets		3	3
Renewable Resources and Environmental Initiatives
Regulatory Assets [Line Items]
Regulatory Asset, Current		170	129
Regulatory assets		$ 3	1
Renewable Resources and Environmental Initiatives | Minimum [Member]
Regulatory Assets [Line Items]
Regulatory Asset, Amortization Period		1 year
Renewable Resources and Environmental Initiatives | Maximum [Member]
Regulatory Assets [Line Items]
Regulatory Asset, Amortization Period		2 years
Gas Pipeline Inspection and Remediation Costs
Regulatory Assets [Line Items]
Regulatory Asset, Current		$ 33	26
Regulatory assets		$ 0	0
Gas Pipeline Inspection and Remediation Costs | Minimum [Member]
Regulatory Assets [Line Items]
Regulatory Asset, Amortization Period		1 year
Gas Pipeline Inspection and Remediation Costs | Maximum [Member]
Regulatory Assets [Line Items]
Regulatory Asset, Amortization Period		2 years
Net AROs
Regulatory Assets [Line Items]
Regulatory Asset, Current	[3]	$ 0	0
Regulatory assets	[3]	316	(32)
Other
Regulatory Assets [Line Items]
Regulatory Asset, Current		18	16
Regulatory assets		$ 20	$ 23
[1]	Includes the fair value of certain long-term PPAs used to meet energy capacity requirements and valuation adjustments on natural gas commodity purchases.
[2]	Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions.
[3]	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		Dec. 31, 2021	Dec. 31, 2020
Regulatory Liabilities [Line Items]
Regulatory Liability, Current	[1]	$ 117	$ 123
Regulatory Liability, Noncurrent	[1]	1,927	1,896
Deferred income tax adjustments and TCJA refunds
Regulatory Liabilities [Line Items]
Regulatory Liability, Current	[2]	9	9
Regulatory Liability, Noncurrent	[2]	1,256	1,326
Plant Removal Costs
Regulatory Liabilities [Line Items]
Regulatory Liability, Current		0	0
Regulatory Liability, Noncurrent		613	544
Investment Tax Credit Deferrals
Regulatory Liabilities [Line Items]
Regulatory Liability, Current		0	0
Regulatory Liability, Noncurrent		7	8
Contract Valuation Adjustments
Regulatory Liabilities [Line Items]
Regulatory Liability, Current	[3]	29	12
Regulatory Liability, Noncurrent	[3]	0	0
DOE Settlement
Regulatory Liabilities [Line Items]
Regulatory Liability, Current		14	11
Regulatory Liability, Noncurrent		0	0
Deferred Electric Energy Costs
Regulatory Liabilities [Line Items]
Regulatory Liability, Current		14	8
Regulatory Liability, Noncurrent		0	0
Renewable Resources and Environmental Initiatives
Regulatory Liabilities [Line Items]
Regulatory Liability, Current		1	5
Regulatory Liability, Noncurrent		10	0
Other Regulatory Liabilities
Regulatory Liabilities [Line Items]
Regulatory Liability, Current		50	78
Regulatory Liability, Noncurrent		41	18
Other Current Liabilities
Regulatory Liabilities [Line Items]
Entity's Recorded Provision for Revenue Subject To Refund		$ 15	$ 17
[1]	Revenue subject to refund of $15 million and $17 million for 2021 and 2020, respectively, is included in other current liabilities.
[2]	Includes the revaluation of recoverable/regulated plant accumulated deferred income taxes and revaluation impact of non-plant accumulated deferred income taxes due to the TCJA.
[3]	Includes the fair value of certain long-term PPAs used to meet energy capacity requirements and valuation adjustments on natural gas commodity purchases.

Short-Term Debt (Details)

Short-Term Debt (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Short-term Debt [Line Items]
Short-term Debt	$ 0	$ 0	$ 179
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	6	3	32
Short-term Debt, Maximum Amount Outstanding During Period	0	$ 236	$ 116	$ 250
Line of Credit Facility, Interest Rate During Period		0.07%	1.53%	2.05%
Commercial Paper [Member]
Short-term Debt [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	500	$ 500	$ 500	$ 500
Short-term Debt	0	0	179	30
Short-term Debt, Average Outstanding Amount	0	26	10	71
Short-term Debt, Maximum Amount Outstanding During Period	$ 13	$ 317	$ 179	$ 317
Short-term Debt, Weighted Average Interest Rate, at Point in Time			0.18%	2.05%
Line of Credit Facility, Interest Rate During Period	0.15%	0.18%	1.25%	2.59%

Letters of Credit (Details)

Letters of Credit (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Line of Credit Facility [Line Items]
Short-term Debt	$ 0	$ 179
Letter of Credit [Member]
Line of Credit Facility [Line Items]
Short-term Debt	$ 9	$ 10
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	$ 45

Credit Facilities (Details)

Credit Facilities (Details) $ in Millions		12 Months Ended
		Dec. 31, 2021USD ($)	Dec. 31, 2020USD ($)
Line of Credit Facility [Line Items]
Short-term Debt		$ 0	$ 179
Letter of Credit [Member]
Line of Credit Facility [Line Items]
Short-term Debt		9	$ 10
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		$ 45
Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Line Of Credit Facility Debt To Total Capitalization Ratio (as a percent)	[1]	47.00%	47.00%
Line Of Credit Facility Maximum Amount Credit Facility May Be Increased		$ 100
Number Of Additional Periods Revolving Termination Date Can Be Extended Subject To Majority Bank Group Approval	[2]	2
Line Of Credit Facility Maximum Debt To Total Capitalization Ratio Allowed		65.00%
Line Of Credit Facility Minimum Threshhold Percentage Of Subsidiary Assets To Consolidated Assets Required To Initiate Cross Default Provisions		15.00%
Line of Credit Facility, Minimum Amount of Indebtedness in Default to Initiate Cross Default Provisions		$ 75
Line of Credit Facility, Maximum Borrowing Capacity	[3]	500
Drawn	[4]	9
Line of Credit Facility, Remaining Borrowing Capacity		491
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]	(b) All extension requests are subject to majority bank group approval.
[3]	This credit facility matures in June 2024.
[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, 2021	Dec. 31, 2020
Long-Term Borrowings and Other Financing Instruments
Unamortized discount		$ (44)	$ (42)
Unamortized debt expense		(62)	(54)
Long-term Debt, Current Maturities		300	0
Long-term Debt		6,447	5,904
2021		300
2022		400
2023		0
2024		250
2025		0
First Mortgage Bonds | Series Due Aug. 15, 2022 [Member]
Long-Term Borrowings and Other Financing Instruments
Face Amount		$ 300	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	0
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		4.00%
First Mortgage Bonds | Series Due May 15, 2046 [Member]
Long-Term Borrowings and Other Financing Instruments
Face Amount		$ 350	350
Debt Instrument, Interest Rate, Stated Percentage		3.60%
First Mortgage Bonds | Series Due Sept. 15, 2047 [Member]
Long-Term Borrowings and Other Financing Instruments
Face Amount		$ 600	600
Debt Instrument, Interest Rate, Stated Percentage		3.60%
First Mortgage Bonds | Series Due 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	[2]	$ 700	700
Debt Instrument, Interest Rate, Stated Percentage	[2]	2.60%
First Mortgage Bonds | Series Due April 1, 2052
Long-Term Borrowings and Other Financing Instruments
Face Amount	[1]	$ 425	0
Debt Instrument, Interest Rate, Stated Percentage	[1]	3.20%
Long-term Debt
Long-Term Borrowings and Other Financing Instruments
Face Amount		$ 3	$ 0
Letter of Credit [Member]
Long-Term Borrowings and Other Financing Instruments
Line of Credit Facility, Expiration Period		1 year
[1]	2021 financing.
[2]	2020 financing.

Deferred Financing Costs (Detai

Deferred Financing Costs (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Deferred Financing Costs [Abstract]
Deferred Finance Costs, Noncurrent, Net	$ 62	$ 54

Dividend and Other Capital-Rela

Dividend and Other Capital-Related Restrictions (Details) $ in Millions	Dec. 31, 2021USD ($)
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	52.90%
Unrestricted Retained Earnings Per State Regulatory Commissions Dividend Restrictions	$ 1,558
Capitalization, Short term debt, long term debt and equity	14,321
Maximum total capitalization	$ 15,332

Revenues Revenues (Details)

Revenues Revenues (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Total revenue from contracts with customers
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	$ 5,320	$ 4,732	$ 4,840
Retail
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	4,114	3,830	3,934
Retail | Residential
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	1,722	1,667	1,613
Retail | C&I
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	2,353	2,124	2,283
Retail | Other
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	39	39	38
Wholesale
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	442	202	210
Transmission
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	242	238	216
Interchange
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	501	440	459
Other
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	21	22	21
Alternative and Other [Member]
Disaggregation of Revenue [Line Items]
Alternative revenue and other	436	369	272
Regulated Electric | Total revenue from contracts with customers
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	4,706	4,238	4,264
Regulated Electric | Retail
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	3,514	3,343	3,367
Regulated Electric | Retail | Residential
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	1,374	1,375	1,280
Regulated Electric | Retail | C&I
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	2,107	1,935	2,054
Regulated Electric | Retail | Other
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	33	33	33
Regulated Electric | Wholesale
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	442	202	210
Regulated Electric | Transmission
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	242	238	216
Regulated Electric | Interchange
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	501	440	459
Regulated Electric | Other
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	7	15	12
Regulated Electric | Alternative and Other [Member]
Disaggregation of Revenue [Line Items]
Alternative revenue and other	388	333	242
Regulated Natural Gas | Total revenue from contracts with customers
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	575	457	541
Regulated Natural Gas | Retail
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	561	450	532
Regulated Natural Gas | Retail | Residential
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	315	261	303
Regulated Natural Gas | Retail | C&I
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	246	189	229
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	14	7	9
Regulated Natural Gas | Alternative and Other [Member]
Disaggregation of Revenue [Line Items]
Alternative revenue and other	48	36	30
All Other | Total revenue from contracts with customers
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	39	37	35
All Other | Retail
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	39	37	35
All Other | Retail | Residential
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers	33	31	30
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	6	6	5
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	5,756	5,101	5,112
Total revenues | Regulated Electric
Disaggregation of Revenue [Line Items]
Total revenues	5,094	4,571	4,506
Total revenues | Regulated Natural Gas
Disaggregation of Revenue [Line Items]
Total revenues	623	493	571
Total revenues | All Other
Disaggregation of Revenue [Line Items]
Total revenues	$ 39	$ 37	$ 35

Federal Loss Carryback

Federal Loss Carryback $ in Millions	12 Months Ended
	Dec. 31, 2021USD ($)
Income Tax Disclosure [Abstract]
Tax Adjustments, Settlements, and Unusual Provisions	$ 13

State Audits

State Audits $ in Millions	12 Months Ended
	Dec. 31, 2021USD ($)
Income Tax Disclosure [Abstract]
Potential Federal Tax Adjustments	$ 0

Unrecognized Tax Benefits

Unrecognized Tax Benefits - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019	Jan. 01, 2021	Jan. 01, 2020	Jan. 01, 2019
Income Tax Disclosure [Abstract]
Unrecognized tax benefit — Permanent tax positions	$ 23	$ 21
Unrecognized tax benefit — Temporary tax positions	3	3
Total unrecognized tax benefit	26	24	$ 20	$ 24	$ 20	$ 17
Additions based on tax positions related to the current year	2	2	3
Reductions based on tax positions related to the current year	0	0	(1)
Additions for tax positions of prior years	0	16	1
Reductions for tax positions of prior years	0	(14)	0
NOL and tax credit carryforwards	(13)	(11)
Decrease in Unrecognized Tax Benefits is Reasonably Possible	14
Unrecognized Tax Benefits, Income Tax Penalties Expense	0	0	0
Payable for interest related to unrecognized tax benefits at Jan. 1	(2)	(2)	(2)	$ (2)	$ (2)	$ (1)
Interest expense related to unrecognized tax benefits	$ 0	$ 0	$ (1)

Other Income Tax Matters

Other Income Tax Matters - USD ($) $ in Millions		3 Months Ended	12 Months Ended
		Dec. 31, 2021	Dec. 31, 2021	Dec. 31, 2020		Dec. 31, 2019
Income Tax [Line Items]
Federal NOL carryforward		$ 77	$ 77	$ 0
Federal tax credit carryforwards		704	704	543
State NOL carryforwards		344	344	151
Valuation allowances for state NOL carryforwards		(1)	(1)	(1)
State tax credit carryforwards, net of federal detriment (a)	[1]	78	78	71
Valuation allowances for state credit carryforwards, net of federal benefit (b)	[2]	$ (64)	$ (64)	$ (59)
Federal statutory rate			21.00%	21.00%		21.00%
State income tax on pretax income, net of federal tax effect			7.00%	7.00%		7.10%
Wind PTCs			(27.80%)	(19.30%)		(11.80%)
Plant regulatory differences (a)	[3]		(8.10%)	(7.20%)		(7.40%)
Other tax credits, net NOL & tax credit allowances			(1.40%)	(1.20%)		(1.50%)
Change in unrecognized tax benefits			0.50%	1.00%		0.50%
NOL Carryback		0.00%		(2.10%)		0.00%
Other, net			0.20%	(0.20%)		0.10%
Effective income tax rate			(8.60%)	(1.00%)		8.00%
Income tax (benefit) expense			$ (48)	$ (6)		$ 47
Deferred tax expense excluding items below			109	61		97
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities			(145)	(127)		(135)
Tax expense allocated to other comprehensive income, adoption of ASC Topic 326, and other			0	(1)		(1)
Deferred tax benefit		$ (36)	(36)	(67)		39
Deferred fuel costs		92	92	7	[4]
Present value of minimum obligation		443	443
income tax expense [Member]
Income Tax [Line Items]
Current federal tax (benefit) expense			(10)	41		80
Current state tax (benefit) expense			(1)	12		8
Current change in unrecognized tax expense (benefit)			1	9		(1)
Deferred federal tax benefit			(87)	(102)		(86)
Deferred state tax expense			49	38		43
Deferred change in unrecognized tax expense (benefit)			2	(3)		4
Deferred ITCs			(2)	(1)		(1)
Income tax (benefit) expense			(48)	(6)		$ 47
Net Deferred Tax Liablility [Member]
Income Tax [Line Items]
Federal tax credit carryforwards		782	782	614	[4]
Deferred ITCs			5	5	[4]
Deferred tax benefit		(1,291)	(1,291)	(1,145)	[4]
Differences between book and tax bases of property			2,679	2,482	[4]
Regulatory assets		260	260	270	[4]
Operating lease assets		123	123	147	[4]
Pension expense		73	73	72	[4]
Other		13	13	7	[4]
Total deferred tax liabilities		3,240	3,240	2,985	[4]
Regulatory Liabilities		325	325	349	[4]
Present value of minimum obligation		123	123	147	[4]
NOL and tax credit valuation allowances		(64)	(64)	(59)	[4]
Other employee benefits		32	32	38	[4]
NOL carryforward		43	43	12	[4]
Other		45	45	39	[4]
Net deferred tax liability		1,949	1,949	1,840	[4]
State and Local Jurisdiction
Income Tax [Line Items]
Federal detriment		21	21	19
Federal Benefit		$ 17	$ 17	$ 16
[1]	State tax credit carryforwards are net of federal detriment of $21 million and $19 million as of Dec. 31, 2021 and 2020, respectively.
[2]	Valuation allowances for state tax credit carryforwards were net of federal benefit of $17 million and $16 million as of Dec. 31, 2021 and 2020, respectively.
[3]	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 credits are offset by corresponding revenue reductions.
[4]	Prior periods have been reclassified to conform to current year presentation

Nuclear Decommissioning Fund (D

Nuclear Decommissioning Fund (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021		Dec. 31, 2020
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Unrealized Gain on Securities	$ 1,300		$ 981
Unrealized Loss on Securities	7		5
Investments [Abstract]
Miscellaneous investments	52		53
Final Contractual Maturity [Abstract]
Due in 1 Year or Less	(4)
Due in 1 to 5 Years	149
Due in 5 to 10 Years	208
Due after 10 Years	314
Total	675
Nuclear Decommissioning Fund [Member] | Fair Value Measured on a Recurring Basis | Cost
Investments [Abstract]
Decommissioning Fund Investments	1,962	[1]	1,801	[2]
Nuclear Decommissioning Fund [Member] | Fair Value Measured on a Recurring Basis | Cost | Cash equivalents
Investments [Abstract]
Cash equivalents	64	[1]	40	[2]
Nuclear Decommissioning Fund [Member] | Fair Value Measured on a Recurring Basis | Cost | Commingled Funds
Investments [Abstract]
Comingled funds	856	[1]	787	[2]
Nuclear Decommissioning Fund [Member] | Fair Value Measured on a Recurring Basis | Cost | Debt Securities [Member]
Investments [Abstract]
Debt securities	631	[1]	528	[2]
Nuclear Decommissioning Fund [Member] | Fair Value Measured on a Recurring Basis | Cost | Equity Securities
Investments [Abstract]
Equity securities	411	[1]	446	[2]
Nuclear Decommissioning Fund [Member] | Fair Value Measured on a Recurring Basis | Fair Value
Investments [Abstract]
Alternative Investment	1,294	[1]	1,041	[2]
Decommissioning Fund Investments	3,256	[1]	2,777	[2]
Nuclear Decommissioning Fund [Member] | Fair Value Measured on a Recurring Basis | Fair Value | Cash equivalents
Investments [Abstract]
Cash equivalents	64	[1]	40	[2]
Alternative Investment	0	[1]	0	[2]
Nuclear Decommissioning Fund [Member] | Fair Value Measured on a Recurring Basis | Fair Value | Commingled Funds
Investments [Abstract]
Comingled funds	1,294	[1]	1,041	[2]
Alternative Investment	1,294	[1]	1,041	[2]
Nuclear Decommissioning Fund [Member] | Fair Value Measured on a Recurring Basis | Fair Value | Debt Securities [Member]
Investments [Abstract]
Debt securities	675	[1]	585	[2]
Alternative Investment	0	[1]	0	[2]
Nuclear Decommissioning Fund [Member] | Fair Value Measured on a Recurring Basis | Fair Value | Equity Securities
Investments [Abstract]
Equity securities	1,223	[1]	1,111	[2]
Alternative Investment	0	[1]	0	[2]
Nuclear Decommissioning Fund [Member] | Fair Value Measured on a Recurring Basis | Fair Value | Level 1
Investments [Abstract]
Decommissioning Fund Investments	1,286	[1]	1,149	[2]
Nuclear Decommissioning Fund [Member] | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | Cash equivalents
Investments [Abstract]
Cash equivalents	64	[1]	40	[2]
Nuclear Decommissioning Fund [Member] | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | Commingled Funds
Investments [Abstract]
Comingled funds	0	[1]	0	[2]
Nuclear Decommissioning Fund [Member] | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | Debt Securities [Member]
Investments [Abstract]
Debt securities	0	[1]	0	[2]
Nuclear Decommissioning Fund [Member] | Fair Value Measured on a Recurring Basis | Fair Value | Level 1 | Equity Securities
Investments [Abstract]
Equity securities	1,222	[1]	1,109	[2]
Nuclear Decommissioning Fund [Member] | Fair Value Measured on a Recurring Basis | Fair Value | Level 2
Investments [Abstract]
Decommissioning Fund Investments	667	[1]	574	[2]
Nuclear Decommissioning Fund [Member] | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | Cash equivalents
Investments [Abstract]
Cash equivalents	0	[1]	0	[2]
Nuclear Decommissioning Fund [Member] | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | Commingled Funds
Investments [Abstract]
Comingled funds	0	[1]	0	[2]
Nuclear Decommissioning Fund [Member] | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | Debt Securities [Member]
Investments [Abstract]
Debt securities	666	[1]	572	[2]
Nuclear Decommissioning Fund [Member] | Fair Value Measured on a Recurring Basis | Fair Value | Level 2 | Equity Securities
Investments [Abstract]
Equity securities	1	[1]	2	[2]
Nuclear Decommissioning Fund [Member] | Fair Value Measured on a Recurring Basis | Fair Value | Level 3
Investments [Abstract]
Decommissioning Fund Investments	9	[1]	13	[2]
Nuclear Decommissioning Fund [Member] | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | Cash equivalents
Investments [Abstract]
Cash equivalents	0	[1]	0	[2]
Nuclear Decommissioning Fund [Member] | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | Commingled Funds
Investments [Abstract]
Comingled funds	0	[1]	0	[2]
Nuclear Decommissioning Fund [Member] | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | Debt Securities [Member]
Investments [Abstract]
Debt securities	9	[1]	13	[2]
Nuclear Decommissioning Fund [Member] | Fair Value Measured on a Recurring Basis | Fair Value | Level 3 | Equity Securities
Investments [Abstract]
Equity securities	$ 0	[1]	$ 0	[2]
[1]	Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $52 million of rabbi trust assets and miscellaneous investments.
[2]	Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $53 million of rabbi trust assets and miscellaneous investments.

Rabbi Trust (Details)

Rabbi Trust (Details) - Rabbi Trust [Member] - Fair Value Measured on a Recurring Basis - USD ($) $ in Millions		Dec. 31, 2021	[1]	Dec. 31, 2020
Cost
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total		$ 10		$ 15	[2]
Cost | Cash
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	[2]			1
Cost | Mutual Fund [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Mutual funds		10		14	[2]
Fair Value
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total		13		17	[2]
Fair Value | Cash
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	[2]			1
Fair Value | Mutual Fund [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Mutual funds		13		16	[2]
Fair Value | Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total		13		17	[2]
Fair Value | Level 1 | Cash
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	[2]			1
Fair Value | Level 1 | Mutual Fund [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Mutual funds		13		16	[2]
Fair Value | Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total		0		0	[2]
Fair Value | Level 2 | Cash
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	[2]			0
Fair Value | Level 2 | Mutual Fund [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Mutual funds		0		0	[2]
Fair Value | Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total		0		0	[2]
Fair Value | Level 3 | Cash
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	[2]			0
Fair Value | Level 3 | Mutual Fund [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Mutual funds		$ 0		$ 0	[2]
[1]	Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet.
[2]	Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet.

Interest Rate Derivatives (Deta

Interest Rate Derivatives (Details) $ in Millions	Dec. 31, 2021USD ($)
Interest Rate Swap [Member]
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

Commodity Derivatives (Details)

Commodity Derivatives (Details) MWh in Millions, MMBTU in Millions, $ in Millions		Dec. 31, 2021USD ($)MMBTUMWh	Dec. 31, 2020MMBTUMWh
Derivative [Line Items]
Commodity contracts designated as cash flow hedges | $		$ 0
Electric Commodity
Derivative [Line Items]
Notional amount | MWh	[1],[2]	57	65
Natural Gas Commodity
Derivative [Line Items]
Notional amount | MMBTU	[1],[2]	85	83
[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, 2021USD ($)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	6
External Credit Rating, Investment Grade
Derivative [Line Items]
Number of most significant counterparties	8
Credit exposure for the most significant counterparties | $	$ 33
Percentage of credit exposure for the most significant counterparties	63.00%
Internal Investment Grade [Member]
Derivative [Line Items]
Number of most significant counterparties	1
Credit exposure for the most significant counterparties | $	$ 17
Percentage of credit exposure for the most significant counterparties	34.00%
External Credit Rating, Non Investment Grade
Derivative [Line Items]
Number of most significant counterparties	1
Percentage of credit exposure for the most significant counterparties	1.00%

Qualifying Cash Flow Hedges (De

Qualifying Cash Flow Hedges (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Financial Impact of Qualifying Cash Flow Hedges on Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Accumulated other comprehensive loss related to cash flow hedges at Jan. 1		$ (19)	$ (20)	$ (20)
After-tax net realized losses on derivative transactions reclassified into earnings		2	1	0
Accumulated other comprehensive loss related to cash flow hedges at Dec. 31		(17)	(19)	(20)
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract]
Fair Value Hedges, Net		0	0	0
Not Designated as Hedging Instrument
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract]
Pre-tax fair value gains (losses) recognized during the period in accumulated other comprehensive loss		0	0	0
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities		0	0	1
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss		0	0	0
Pre-tax gains (losses) reclassified into income during the period from regulatory assets and (liabilities)		(2)	1	(2)
Derivative, Gain (Loss) on Derivative, Net		45	(9)	(3)
Not Designated as Hedging Instrument | Electric Commodity Contract
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		(3)	(2)	(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]	(3)	3	(1)
Derivative, Gain (Loss) on Derivative, Net		0	0	0
Not Designated as Hedging Instrument | Natural Gas Commodity Contract
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		3	2	3
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss		0	0	0
Pre-tax gains (losses) reclassified into income during the period from regulatory assets and (liabilities)	[2]	(1)	(2)	1
Derivative, Gain (Loss) on Derivative, Net	[2]	(6)	(4)	$ (3)
Not Designated as Hedging Instrument | Commodity Trading Contract
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
Pre-tax gains (losses) reclassified into income during the period from regulatory assets and (liabilities)		0	0
Derivative, Gain (Loss) on Derivative, Net	[3]	51	(5)
Designated as Hedging Instrument | Cash Flow Hedges
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		2	1
Pre-tax gains (losses) reclassified into income during the period from regulatory assets and (liabilities)		0	0
Derivative, Gain (Loss) on Derivative, Net		0	0
Designated as Hedging Instrument | Cash Flow Hedges | Interest Rate Contract
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	[4]	2	1
Pre-tax gains (losses) reclassified into income during the period from regulatory assets and (liabilities)		0	0
Derivative, Gain (Loss) on Derivative, Net		$ 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.
[2]	Amounts are recorded to cost of natural gas sold and transported. These derivative settlement gains and losses are shared with natural gas customers through purchased natural gas cost-recovery mechanisms and reclassified out of income as regulatory assets and liabilities, as appropriate.
[3]	Amounts are recorded to cost of natural gas sold and transported. These derivative settlement gains and losses are shared with natural gas customers through purchased natural gas cost-recovery mechanisms and reclassified out of income as regulatory assets and liabilities, as appropriate.
[4]	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.

Credit Related Contingent Featu

Credit Related Contingent Features (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Fair Value Disclosures [Abstract]
Derivative instruments in a gross liability position	$ 3	$ 4
Derivative, Gross Liability with Cross Default Position, Aggregate Fair Value	48	14
Collateral posted related to adequate assurance clauses in derivative contracts	$ 0	$ 0

Recurring Fair Value Measuremen

Recurring Fair Value Measurements (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Derivatives, Fair Value [Line Items]
Return Cash Collateral		$ 0	$ 15
Reclaim Cash Collateral		16	1
Commodity Contract [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Balance at beginning of period		(11)	5	$ 14
Purchases		54	28	17
Settlements		(82)	(49)	(28)
Gains (losses) recognized in earnings	[1]	72	(8)	3
Net gains (losses) recognized as regulatory assets and liabilities		23	13	(1)
Balance at end of period		56	(11)	5
Transfers Between Levels, Net		0	0	$ 0
Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Net		35	22
Other Noncurrent Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Net		71	71
Fair Value Measured on a Recurring Basis | Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		107	43
Netting	[2]	(54)	(26)
Derivative Asset, Net		53	17
Fair Value Measured on a Recurring Basis | Other Current Assets | Level 1
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		9	1
Fair Value Measured on a Recurring Basis | Other Current Assets | Level 2
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		46	29
Fair Value Measured on a Recurring Basis | Other Current Assets | Level 3
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		52	13
Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments | Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		71	27
Netting	[2]	(53)	(25)
Derivative Asset, Net		18	2
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		9	1
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		40	26
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		22	0
Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		30	13
Netting	[2]	(1)	(1)
Derivative Asset, Net		29	12
Fair Value Measured on a Recurring Basis | Other Current Assets | 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 Current Assets | 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 Current Assets | Other Derivative Instruments | Electric Commodity | Level 3
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		30	13
Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		6	3
Netting	[2]	0	0
Derivative Asset, Net		6	3
Fair Value Measured on a Recurring Basis | Other Current Assets | 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 Current Assets | Other Derivative Instruments | Natural Gas Commodity | Level 2
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		6	3
Fair Value Measured on a Recurring Basis | Other Current Assets | 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 Noncurrent Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		75	46
Netting	[2]	(42)	(41)
Derivative Asset, Net		33	5
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets | Level 1
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		6	7
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets | Level 2
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		34	39
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets | Level 3
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		35	0
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets | Other Derivative Instruments | Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		75	46
Netting	[2]	(42)	(41)
Derivative Asset, Net		33	5
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		6	7
Fair Value Measured on a Recurring Basis | Other Noncurrent Assets | Other Derivative Instruments | Commodity Contract [Member] | Level 2
Derivatives, Fair Value [Line Items]
Derivative Asset, Gross		34	39
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		35	0
Fair Value Measured on a Recurring Basis | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		80	34
Netting	[2]	(59)	(26)
Derivative Liability, Net		21	8
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Level 1
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		13	3
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Level 2
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		62	20
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Level 3
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		5	11
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		75	31
Netting	[2]	(58)	(25)
Derivative Liability, Net		17	6
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		13	3
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		58	18
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		4	10
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		1	1
Netting	[2]	(1)	(1)
Derivative Liability, Net		0	0
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	0
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Electric Commodity | Level 3
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		1	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		4	2
Netting	[2]	0	0
Derivative Liability, Net		4	2
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		4	2
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Natural Gas Commodity | Level 3
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		0	0
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		89	50
Netting	[2]	(53)	(27)
Derivative Liability, Net		36	23
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities | Level 1
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		15	2
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities | Level 2
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		48	35
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities | Level 3
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		26	13
Fair Value Measured on a Recurring Basis | Other Noncurrent Liabilities | Other Derivative Instruments | Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Gross		89	50
Netting	[2]	(53)	(27)
Derivative Liability, Net		36	23
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		15	2
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		48	35
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		26	13
Fair Value, Measurements, Nonrecurring | Other Current Liabilities | Purchased Power Agreements
Derivatives, Fair Value [Line Items]
Derivative Liability, Net	[3]	14	14
Fair Value, Measurements, Nonrecurring | Other Noncurrent Liabilities | Purchased Power Agreements
Derivatives, Fair Value [Line Items]
Derivative Liability, Net	[3]	$ 35	$ 48
[1]	Level 3 losses and gains recognized in earnings are subject to offsetting gains and losses of derivative instruments categorized as levels 1 and 2 in the income statement.
[2]	NSP-Minnesota nets derivative instruments and related collateral on its consolidated balance sheets when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Dec. 31, 2021 and 2020. At Dec. 31, 2021 derivative assets and liabilities include no obligations to return cash collateral. At Dec. 31, 2020 derivative assets and liabilities include $15 million of obligations to return cash collateral. At Dec. 31, 2021 and 2020, derivative assets and liabilities include the rights to reclaim cash collateral of $16 million and $1 million, respectively. The counterparty netting excludes settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.
[3]	During 2006, Xcel Energy qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be 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, 2021	Dec. 31, 2020
Financial Liabilities, Balance Sheet Groupings [Abstract]
Long-term Debt, Gross	$ 6,747	$ 5,904
Long-term debt, Fair Value	$ 7,761	$ 7,391

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, 2021	Dec. 31, 2020	Dec. 31, 2019
Defined Benefit Plan Disclosure [Line Items]
annual interest crediting rates	$ 1.96	$ 1.78	$ 2.74
asset transferred	0
Supplemental Executive Retirement Plan (SERP) and Nonqualified Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Total benefit obligation	$ 3,000,000	$ 4,000,000

Benefit Plans and Other Postr_4

Benefit Plans and Other Postretirement Benefits, Pension Benefits (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2022	Dec. 31, 2021		Dec. 31, 2020		Dec. 31, 2019
Supplemental Executive Retirement Plan (SERP) and Nonqualified Pension Plan
Pension Benefits [Abstract]
Total benefit obligation			$ 3		$ 4
Net benefit cost recognized for financial reporting					1
Pension Plan
Pension Benefits [Abstract]
Fair value of plan assets			853	[1]	897	[1]	$ 815
Total benefit obligation			877		989		942
Net benefit cost recognized for financial reporting			$ 28		$ 32		$ 33
Expected average long-term rate of return on assets (as a percent)			6.60%		7.10%		7.10%
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (as a percent)			100.00%		100.00%
Pension Plan | Domestic and international equity securities
Pension Benefits [Abstract]
Fair value of plan assets	[1]		$ 16		$ 20
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (as a percent)			33.00%		35.00%
Pension Plan | Long-duration fixed income and interest rate swap securities
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (as a percent)			37.00%		35.00%
Pension Plan | Short-to-intermediate fixed income securities
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (as a percent)			11.00%		13.00%
Pension Plan | Alternative investments
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (as a percent)			17.00%		15.00%
Pension Plan | Cash
Pension Benefits [Abstract]
Fair value of plan assets	[1]		$ 31		$ 52
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (as a percent)			2.00%		2.00%
Xcel Energy Inc. | Supplemental Executive Retirement Plan (SERP) and Nonqualified Pension Plan
Pension Benefits [Abstract]
Total benefit obligation			$ 43		$ 43
Net benefit cost recognized for financial reporting			$ 4		$ 6
Forecast [Member] | Pension Plan
Pension Benefits [Abstract]
Expected average long-term rate of return on assets for next fiscal year (as a percent)		6.60%
[1]	See Note 8 for further information on 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, 2021		Dec. 31, 2020		Dec. 31, 2019
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount		$ 853	[1]	$ 897	[1]	$ 815
Plan assets at net asset value	[1]	281		284
Level 1
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	[1]	351		444
Level 2
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	[1]	220		168
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]	31		52
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]	31		52
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]	578		653
Plan assets at net asset value	[1]	274		284
Commingled Funds | Level 1
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	[1]	304		369
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]	220		168
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]	219		167
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]	16		20
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]	16		20
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]	8		4
Plan assets at net asset value	[1]	7		0
Other | Level 1
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Amount	[1]	0		3
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 on fair value measurement inputs and methods.

Benefit Plans and Other Postr_6

Benefit Plans and Other Postretirement Benefits, Pension Plan Benefit Obligations, Cash Flows and Benefit Costs (Details) $ in Millions		1 Months Ended		12 Months Ended
		Jan. 31, 2022USD ($)		Dec. 31, 2021USD ($)plan		Dec. 31, 2020USD ($)		Dec. 31, 2019USD ($)
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				$ (112)		$ (192)
Pension Plan
Change in Projected Benefit Obligation [Roll Forward]
Obligation at Jan. 1		$ 877		989		942
Service cost				30		27		$ 25
Interest cost				25		31		37
Plan amendments				1		0
Actuarial (gain) loss				(28)		84
Benefit payments				(140)		(95)
Obligation at Dec. 31				877		989		942
Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1		853	[1]	897	[1]	815
Actual return (loss) on plan assets				62		133
Employer contributions				34		44
Benefit payments				(140)		(95)
Fair value of plan assets at Dec. 31				853	[1]	897	[1]	815
Funded Status of Plans at Dec. 31 [Abstract]
Funded status				(24)		(92)
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost [Abstract]
Net loss				307		414
Prior service (credit) cost				0		0
Total				307		414
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				25		29
Noncurrent regulatory assets				282		385
Total				$ 307		$ 414
Significant Assumptions Used to Measure Benefit Obligations [Abstract]
Discount rate for year-end valuation (as a percent)				3.08%		2.71%
Expected average long-term increase in compensation level (as a percent)				3.75%		3.75%
Components of Net Periodic Benefit Cost (Credit) [Abstract]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement	[2]			$ (35)		$ 0		$ 0
Defined Benefit Plan, Accumulated Benefit Obligation				811		912
Liability, Defined Benefit Plan, Current				0		0
Liability, Defined Benefit Plan, Noncurrent				(24)		(92)
Defined Benefit Plan, Amounts for Asset (Liability) Recognized in Statement of Financial Position				$ (24)		$ (92)
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate				2.71%		3.49%		4.31%
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				$ (811)		$ (912)
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Rate of Return on Plan Assets				6.60%		7.10%		7.10%
Service cost				$ 30		$ 27		$ 25
Interest cost				25		31		37
Expected return on plan assets				(52)		(55)		(54)
Amortization of prior service cost (credit)				0		0		0
Amortization of net loss				34		33		30
Net periodic pension cost				72		36		38
Effects of regulation				(44)		(4)		(5)
Net benefit cost recognized for financial reporting				28		32		33
Pension Plan | NSP Minnesota [Member]
Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1	[3]			2
Fair value of plan assets at Dec. 31	[3]					2
Cash Flows [Abstract]
Total contributions to Xcel Energy's pension plans during the period				$ 34		$ 44		$ 47
Subsequent Event | Pension Plan | NSP Minnesota [Member]
Cash Flows [Abstract]
Total contributions to Xcel Energy's pension plans during the period		$ 5
[1]	See Note 8 for further information on 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 2021, as a result of lump-sum distributions during the 2021 plan year, NSP-Minnesota recorded a total pension settlement charge of $35 million in 2021, which was not recognized due to the effects of regulation. There were no settlement charges recorded to the qualified pension plans in 2020 and 2019.
[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, 2021	Dec. 31, 2020	Dec. 31, 2019
Postretirement Benefits Plan
Postretirement Health Care Benefits [Abstract]
Total benefit obligation	$ 64	$ 73	$ 76
Defined Benefit Plan, Net Periodic Benefit Cost (Credit)	$ 1	$ 0	$ 2
Target pension asset allocations (as a percent)	100.00%	100.00%
Supplemental Executive Retirement Plan (SERP) and Nonqualified Pension Plan
Postretirement Health Care Benefits [Abstract]
Total benefit obligation	$ 3	$ 4
Defined Benefit Plan, Net Periodic Benefit Cost (Credit)		1
Supplemental Executive Retirement Plan (SERP) and Nonqualified Pension Plan | Parent Company [Member]
Postretirement Health Care Benefits [Abstract]
Total benefit obligation	43	43
Defined Benefit Plan, Net Periodic Benefit Cost (Credit)	$ 4	$ 6
Domestic and international equity securities | Postretirement Benefits Plan
Postretirement Health Care Benefits [Abstract]
Target pension asset allocations (as a percent)	15.00%	15.00%
Long-duration fixed income and interest rate swap securities | Postretirement Benefits Plan
Postretirement Health Care Benefits [Abstract]
Target pension asset allocations (as a percent)	0.00%	0.00%
Short-to-intermediate fixed income securities | Postretirement Benefits Plan
Postretirement Health Care Benefits [Abstract]
Target pension asset allocations (as a percent)	71.00%	72.00%
Alternative investments | Postretirement Benefits Plan
Postretirement Health Care Benefits [Abstract]
Target pension asset allocations (as a percent)	8.00%	9.00%
Cash | Postretirement Benefits Plan
Postretirement Health Care Benefits [Abstract]
Target pension asset allocations (as a percent)	6.00%	4.00%

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, 2021		Dec. 31, 2020	Dec. 31, 2019
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		$ 3	[1]	$ 2	$ 3
Plan assets at net asset value	[1]	1		0
Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	[1]	0		0
Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	[1]	2		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]	1		0
Plan assets at net asset value	[1]	1		0
Commingled Funds | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	[1]	0		0
Commingled Funds | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	[1]	0		0
Commingled Funds | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	[1]	$ 0		$ 0
[1]	See Note 8 for further information on fair value measurement inputs and methods.

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, 2021		Dec. 31, 2020		Dec. 31, 2019
Funded Status of Plans at Dec. 31 [Abstract]
Noncurrent liabilities		$ (112,000,000)		$ (192,000,000)
Significant Assumptions Used to Measure Costs [Abstract]
Plan Amendments		0
Pension Plan
Change in Projected Benefit Obligation [Roll Forward]
Obligation at Jan. 1		989,000,000		942,000,000
Service cost		30,000,000		27,000,000		$ 25,000,000
Interest cost		25,000,000		31,000,000		37,000,000
Actuarial (gain) loss		(28,000,000)		84,000,000
Benefit payments		(140,000,000)		(95,000,000)
Obligation at Dec. 31		877,000,000		989,000,000		942,000,000
Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1		897,000,000	[1]	815,000,000
Actual return (loss) on plan assets		62,000,000		133,000,000
Employer contributions		34,000,000		44,000,000
Benefit payments		(140,000,000)		(95,000,000)
Fair value of plan assets at Dec. 31		853,000,000	[1]	897,000,000	[1]	815,000,000
Funded Status of Plans at Dec. 31 [Abstract]
Funded status		(24,000,000)		(92,000,000)
Current liabilities		0		0
Noncurrent liabilities		(24,000,000)		(92,000,000)
Net postretirement amounts recognized on consolidated balance sheets		(24,000,000)		(92,000,000)
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost [Abstract]
Net loss		307,000,000		414,000,000
Prior service (credit) cost		0		0
Total		307,000,000		414,000,000
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		282,000,000		385,000,000
Deferred income taxes		0		0
Net-of-tax accumulated other comprehensive income		0		0
Total		$ 307,000,000		$ 414,000,000
Significant Assumptions Used to Measure Benefit Obligations [Abstract]
Discount rate for year-end valuation (as a percent)		3.08%		2.71%
Components of Net Periodic Benefit Cost (Credit) [Abstract]
Service cost		$ 30,000,000		$ 27,000,000		25,000,000
Interest cost		25,000,000		31,000,000		37,000,000
Expected return on plan assets		(52,000,000)		(55,000,000)		(54,000,000)
Amortization of prior service cost (credit)		0		0		0
Amortization of net loss		34,000,000		33,000,000		30,000,000
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement	[2]	35,000,000		0		0
Net periodic postretirement benefit cost		72,000,000		36,000,000		38,000,000
Significant Assumptions Used to Measure Costs [Abstract]
Plan amendments		1,000,000		0
Amounts Not Yet Recognized As Components Of Net Periodic Benefit Cost Recorded As Current Regulatory Assets		25,000,000		29,000,000
Defined Benefit Plan Credits (Costs) Not Recognized Due To Effects of Regulation		(44,000,000)		(4,000,000)		(5,000,000)
Net benefit cost recognized for financial reporting		$ 28,000,000		$ 32,000,000		$ 33,000,000
Discount rate (as a percent)		2.71%		3.49%		4.31%
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%		7.10%		7.10%
Postretirement Benefits Plan
Change in Projected Benefit Obligation [Roll Forward]
Obligation at Jan. 1		$ 73,000,000		$ 76,000,000
Service cost		0		0		$ 0
Interest cost		2,000,000		2,000,000		3,000,000
Actuarial (gain) loss		(5,000,000)		2,000,000
Benefit payments		(6,000,000)		(7,000,000)
Obligation at Dec. 31		64,000,000		73,000,000		76,000,000
Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1		2,000,000		3,000,000
Actual return (loss) on plan assets		0		0
Employer contributions		7,000,000		6,000,000
Benefit payments		(6,000,000)		(7,000,000)
Fair value of plan assets at Dec. 31		3,000,000	[3]	2,000,000		3,000,000
Funded Status of Plans at Dec. 31 [Abstract]
Funded status		(61,000,000)		(71,000,000)
Current liabilities		(3,000,000)		(5,000,000)
Noncurrent liabilities		(58,000,000)		(66,000,000)
Net postretirement amounts recognized on consolidated balance sheets		(61,000,000)		(71,000,000)
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost [Abstract]
Net loss		31,000,000		37,000,000
Prior service (credit) cost		(4,000,000)		(6,000,000)
Total		27,000,000		31,000,000
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		25,000,000		29,000,000
Deferred income taxes		1,000,000		1,000,000
Net-of-tax accumulated other comprehensive income		1,000,000		1,000,000
Total		$ 27,000,000		$ 31,000,000
Significant Assumptions Used to Measure Benefit Obligations [Abstract]
Discount rate for year-end valuation (as a percent)		3.09%		2.65%
Defined Benefit Plan, Health Care Cost Trend Rate Assumed, Pre-65		5.30%		5.50%
Defined Benefit Plan, Health Care Cost Trend Rate Assumed, Post-65		4.90%		5.00%
Ultimate health care trend assumption rate (as a percent)		4.50%		4.50%
Period until ultimate trend rate is reached (in years)		$ 4		$ 5
Components of Net Periodic Benefit Cost (Credit) [Abstract]
Service cost		0		0		0
Interest cost		2,000,000		2,000,000		3,000,000
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		2,000,000		1,000,000		2,000,000
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement	[2]	0		0		0
Net periodic postretirement benefit cost		1,000,000		0		2,000,000
Significant Assumptions Used to Measure Costs [Abstract]
Plan amendments		0		0
Amounts Not Yet Recognized As Components Of Net Periodic Benefit Cost Recorded As Current Regulatory Assets		0		0
Defined Benefit Plan Credits (Costs) Not Recognized Due To Effects of Regulation		0		0		0
Net benefit cost recognized for financial reporting		$ 1,000,000		$ 0		$ 2,000,000
Discount rate (as a percent)		2.65%		3.47%		4.32%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase		0.00%		0.00%		0.00%
Expected average long-term rate of return on assets (as a percent)		4.10%		4.50%		4.50%
[1]	See Note 8 for further information on 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 2021, as a result of lump-sum distributions during the 2021 plan year, NSP-Minnesota recorded a total pension settlement charge of $35 million in 2021, which was not recognized due to the effects of regulation. There were no settlement charges recorded to the qualified pension plans in 2020 and 2019.
[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, 2022	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Defined Benefit Plan, Net Projected Benefit Payments [Abstract]
Defined Contribution Plan, Administrative Expense		$ 12	$ 12	$ 12
Pension Plan
Defined Benefit Plan, Gross Projected Benefit Payments [Abstract]
2022		118
2023		72
2024		68
2025		67
2026		64
2027-2031		292
Pension Plan | Xcel Energy [Member]
Defined Benefit Plan, Net Projected Benefit Payments [Abstract]
Payment for Pension Benefits		131	150	154
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		34	44	47
Pension Plan | NSP Minnesota [Member] | Subsequent Event
Defined Benefit Plan, Net Projected Benefit Payments [Abstract]
Payment for Pension Benefits	5
Postretirement Benefits Plan
Defined Benefit Plan, Gross Projected Benefit Payments [Abstract]
2022		6
2023		6
2024		5
2025		5
2026		5
2027-2031		18
Expected Medicare Part D Subsidies [Abstract]
2022		0
2023		0
2024		0
2025		0
2026		0
2027-2031		0
Defined Benefit Plan, Net Projected Benefit Payments [Abstract]
2022		6
2023		6
2024		5
2025		5
2026		5
2027-2031		18
Defined Benefit Plan, Overfunded Plan [Member] | Xcel Energy [Member]
Defined Benefit Plan, Net Projected Benefit Payments [Abstract]
Payment for Pension Benefits		15	11	15
Defined Benefit Plan, Overfunded Plan [Member] | Xcel Energy [Member] | Subsequent Event
Defined Benefit Plan, Net Projected Benefit Payments [Abstract]
Payment for Pension Benefits	9
Defined Benefit Plan, Overfunded Plan [Member] | NSP Minnesota [Member]
Defined Benefit Plan, Net Projected Benefit Payments [Abstract]
Payment for Pension Benefits		$ 8	$ 6	$ 8
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	12 Months Ended
	Jan. 31, 2021	Dec. 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
Gain (Loss) Related to Litigation Settlement		$ 36

Commitments and Contingencies W

Commitments and Contingencies Westmoreland Arbitration (Details) $ in Millions	12 Months Ended
	Dec. 31, 2021USD ($)
Guarantees and Product Warranties [Abstract]
Gain (Loss) Related to Litigation Settlement	$ 36

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		7 Months Ended	8 Months Ended	9 Months Ended
	Feb. 28, 2015	Nov. 30, 2013	Dec. 31, 2020	Dec. 31, 2020	Sep. 30, 2018
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%
Public Utilities, ROE Applicable To Transmission Formula Rates In The MISO Region, Approved					10.32%
Public Utilities, ROE New Base, Complaint Number 1				10.02%
Basis Point Reduction			1000.00%
Basis Point Reduction - First Complaint			100000000.00%
Basis Point Reduction - Second Complaint			100000000.00%
Basis Point Reduction - Third Complaint			200000000.00%

Commitments and Contingencies_2

Commitments and Contingencies MGP Sites (Details)	Dec. 31, 2021Site
Other MGP, Landfill, or Disposal Sites [Domain]
Loss Contingencies [Line Items]
Number of identified MGP, landfill, or disposal sites under current investigation and/or remediation	7

Commitments and Contingencies E

Commitments and Contingencies Environmental Requirements - Water and Waste (Details) $ in Millions	Dec. 31, 2021USD ($)Plant
Federal Coal Ash Regulation [Domain]
Loss Contingencies [Line Items]
Number of regulated ash units that will still be in operation by the end of 2019	3
Number of sites where statistically significant increases over established groundwater standards exist	0
Number of impoundments where closure plans will be expedited	1
Estimated cost of closure of an impoundment	$ 4
Federal Clean Water Act Section 316 (b) [Member]
Loss Contingencies [Line Items]
Minimum number of plants which could be required to make improvements to reduce entrainment | Plant	6
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	$ 36
Liability for estimated cost to comply with impingement and entrainment regulation	$ 188

Commitment and Contingencies AR

Commitment and Contingencies AROs (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2021		Dec. 31, 2020
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance		$ 2,350		$ 2,280
Amounts Incurred		(107)	[1]	(90)	[2]
Amounts Settled		0		3	[3]
Accretion		116		117
Cash flow revisions		12	[4]	(134)	[5]
Ending balance		2,585	[6]	2,350
Fair Value, Measurements, Recurring | Nuclear Decommissioning Fund [Member] | Estimate of Fair Value Measurement [Member]
Other Commitments [Line Items]
Legally restricted assets, for purposes of funding future nuclear decommissioning		3,256	[7]	2,777	[8]
Electric Plant Nuclear Production Decommissioning
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance		1,957		2,068
Amounts Incurred		0	[1]	0	[2]
Amounts Settled	[3]			0
Accretion		99		105
Cash flow revisions		0	[4]	(216)	[5]
Ending balance		2,056	[6]	1,957
Electric Plant Wind Production
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance		270		113
Amounts Incurred		(101)	[1]	(90)	[2]
Amounts Settled	[3]			0
Accretion		13		7
Cash flow revisions		0	[4]	60	[5]
Ending balance		384	[6]	270
Electric Plant Steam Production Ash Containment
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance		67		47
Amounts Incurred		(6)	[1]	0	[2]
Amounts Settled	[3]			3
Accretion		2		2
Cash flow revisions		(2)	[4]	21	[5]
Ending balance		73	[6]	67
Electric Plant Electric Distribution
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance		16		15
Amounts Incurred		0	[1]	0	[2]
Amounts Settled	[3]			0
Accretion		0		1
Cash flow revisions		0	[4]	0	[5]
Ending balance		16	[6]	16
Electric Plant Other
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance		0		0
Amounts Incurred	[2]			0
Amounts Settled	[3]			0
Accretion				0
Cash flow revisions	[5]			0
Ending balance				0
Natural Gas Plant Gas Transmission and Distribution
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance		39		36
Amounts Incurred		0	[1]	0	[2]
Amounts Settled	[3]			0
Accretion		2		2
Cash flow revisions		14	[4]	1	[5]
Ending balance		55	[6]	39
Common and Other Property Common Miscellaneous
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance		1		1
Amounts Incurred		0	[1]	0	[2]
Amounts Settled	[3]			0
Accretion		0		0
Cash flow revisions		0	[4]	0	[5]
Ending balance		$ 1	[6]	$ 1
[1]	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.
[2]	Amounts incurred relate to the wind farms placed in service in 2020 (Blazing Star 1, Crowned Ridge, Jeffers and Community Wind North).
[3]	Amounts settled related to closure of certain ash containment facilities.
[4]	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.
[5]	In 2020, AROs were revised for changes in timing and estimates of cash flows. Revisions in the nuclear AROs were driven by reductions in spent fuel cooling time requirements in the nuclear triennial filing coupled with decreasing interest rates. Changes in wind AROs were driven by new dismantling studies. Revisions in steam and other production AROs primarily related to changes in cost estimates for remediation of ash containment facilities.
[6]	There were no ARO amounts settled in 2021.
[7]	Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $52 million of rabbi trust assets and miscellaneous investments.
[8]	Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $53 million of rabbi trust assets and miscellaneous investments.

Indeterminate AROs (Details)

Indeterminate AROs (Details) $ in Millions	Dec. 31, 2021USD ($)
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, 2021USD ($)PlantReactor
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	13,000
Maximum assessments per reactor per accident	$ 138
Number of owned and licensed reactors | Reactor	3
Maximum funding requirement per reactor for any one year	$ 21
Number of nuclear plant sites operated by NSP-Minnesota | Plant	2
Maximum assessments for business interruption insurance each calendar year	$ 11
Maximum assessment for property damage insurance NSP-Minnesota is subject to each calendar year	33
Maximum
Nuclear Insurance [Abstract]
Loss Contingency, Estimate of Possible Loss	13,500
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)	Dec. 31, 2021Canister
Monticello [Member]
Loss Contingencies [Line Items]
Number Of Authorized Canisters Filled And Placed In Dry Cask Nuclear Storage Facility	30
Prairie Island [Member]
Loss Contingencies [Line Items]
Number Of Authorized Canisters Filled And Placed In Dry Cask Nuclear Storage Facility	47
Number Of Authorized Canisters In Dry Cask Nuclear Storage Facility	64

Commitments and Contingencies R

Commitments and Contingencies Regulatory Plant Decommissioning Recovery (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2021		Dec. 31, 2020		Dec. 31, 2019
Public Utilities, General Disclosures [Line Items]
Percentage Of Total Obligation For Decommissioning Expected To Be Funded By External Funds		100.00%
Assumed annual escalation rate during operations and radiological portion of decommissioning		4.36%
Assumed annual escalation rate during independent fuel storage installation and site restoration portion of decommissioning		3.36%
Average risk-free interest rate		1.96%		1.64%
Asset Retirement Obligation		$ 2,585	[1]	$ 2,350		$ 2,280
Nuclear Decommissioning Expense	[2],[3]	22		20		20
Approved annual accrual for decommissioning costs		14		14		14
Nuclear Plant [Member]
Public Utilities, General Disclosures [Line Items]
Discounted decommissioning cost obligation		6,554		7,024
Differences in Discount Rate and Market Risk Premium		(2,209)		(2,628)
Operating and Maintenance Costs Not Included for GAAP		(1,584)		(1,734)
ARO differences between 2020 and 2014 cost studies		(705)		(705)
Asset Retirement Obligation		$ 2,056	[1]	1,957		$ 2,068
Minimum [Member]
Public Utilities, General Disclosures [Line Items]
Assumed after tax rate of return used to determine funding for external decommissioning trust fund		5.23%
Maximum [Member]
Public Utilities, General Disclosures [Line Items]
Assumed after tax rate of return used to determine funding for external decommissioning trust fund		6.30%
Nuclear Decommissioning Fund [Member] | Fair Value Measured on a Recurring Basis | Estimate of Fair Value Measurement [Member]
Public Utilities, General Disclosures [Line Items]
Estimated Decommissioning Cost Obligation From Most Recently Approved Study		$ 3,012		3,012
Effect Of Escalating Costs To Current Year Dollars		1,006		844
Estimated Decommissioning Cost Obligation In Current Dollars		4,018		3,856
Effect Of Escalating Costs To Payment Date		7,187		7,349
Estimated Future Decommissioning Costs Undiscounted		11,205		11,205
Effect Of Discounting Obligation Using Risk Free Interest Rate		(4,651)		(4,181)
Discounted decommissioning cost obligation		6,554		7,024
Decommissioning Fund Investments		3,256	[4]	2,777	[5]
Discounted Decommissioning Obligation Compared To Assets Currently Held In Trust		$ 3,298		$ 4,247
[1]	There were no ARO amounts settled in 2021.
[2]	Decommissioning expense does not include depreciation of the capitalized nuclear asset retirement costs.
[3]	Decommissioning expenses in 2021, 2020 and 2019 include Minnesota’s retail jurisdiction annual funding requirement of approximately $14 million.
[4]	Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $52 million of rabbi trust assets and miscellaneous investments.
[5]	Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $53 million of rabbi trust assets and miscellaneous investments.

Commitments and Contingencies_3

Commitments and Contingencies, Leases (Details) - USD ($)		12 Months Ended
		Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Lessee, Lease, Description [Line Items]
Maximum Length - Short-Term Leases		12 months
Short-term Lease, Cost		$ 2,000,000	$ 2,000,000	$ 1,000,000
Operating Lease, Weighted Average Discount Rate, Percent		3.80%
Operating Lease, Assets and Liabilities, Lessee [Abstract]
Operating Lease, Right-of-Use Asset, Gross		$ 630,000,000	632,000,000
Operating Lease, Right-of-Use Asset, Accumulated Depreciation		(222,000,000)	(144,000,000)
Operating lease right-of-use assets		408,000,000	488,000,000
Lease, Cost [Abstract]
Operating Lease, Cost	[1]	104,000,000	97,000,000	85,000,000
Lessee, Operating Lease, Liability, Payment, Due [Abstract]
2022		105,000,000
2023		110,000,000
2024		107,000,000
2025		87,000,000
2026		47,000,000
Thereafter		31,000,000
Total minimum obligation		487,000,000
Interest component of obligation		(44,000,000)
Present value of minimum obligation		443,000,000
Less current portion		(90,000,000)	(85,000,000)
Operating lease liabilities		353,000,000	443,000,000
Weighted Average Remaining lease term, operating		8.5
Property, Plant and Equipment, Other Types [Member]
Operating Lease, Assets and Liabilities, Lessee [Abstract]
Operating Lease, Right-of-Use Asset, Gross		74,000,000	74,000,000
Lease, Cost [Abstract]
Operating Lease, Cost	[2]	8,000,000	8,000,000	9,000,000
Lessee, Operating Lease, Liability, Payment, Due [Abstract]
2022		9,000,000
2023		12,000,000
2024		7,000,000
2025		7,000,000
2026		7,000,000
Thereafter		31,000,000
Total minimum obligation		73,000,000
Interest component of obligation		(12,000,000)
Present value of minimum obligation		61,000,000
Purchased Power Agreements
Operating Lease, Assets and Liabilities, Lessee [Abstract]
Operating Lease, Right-of-Use Asset, Gross		556,000,000	558,000,000
Lease, Cost [Abstract]
Operating Lease, Cost		96,000,000	$ 89,000,000	$ 76,000,000
Lessee, Operating Lease, Liability, Payment, Due [Abstract]
2022	[3],[4]	96,000,000
2023	[3],[4]	98,000,000
2024	[3],[4]	100,000,000
2025	[3],[4]	80,000,000
2026	[3],[4]	40,000,000
Thereafter	[3],[4]	0
Total minimum obligation	[3],[4]	414,000,000
Interest component of obligation	[3],[4]	(32,000,000)
Present value of minimum obligation	[3],[4]	$ 382,000,000
[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 $2 million , $2 million and $1 million for 2021, 2020 and 2019, respectively.
[3]	Amounts do not include PPAs accounted for as executory contracts and/or contingent payments, such as energy payments on renewable PPAs.
[4]	PPA operating leases contractually expire at various dates through 2039.

Commitments and Contingencies_4

Commitments and Contingencies, Purchased Power Agreements (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Energy
Purchased Power Agreements (PPAs) [Abstract]
Purchased power expense		$ 149	$ 112	$ 102
Estimated Future Payments Under PPAs [Abstract]
2022	[1]	165
2023	[1]	169
2024	[1]	174
2025	[1]	53
2026	[1]	10
Thereafter	[1]	38
Total	[1],[2]	609
Capacity
Purchased Power Agreements (PPAs) [Abstract]
Purchased power expense		55	$ 52	$ 54
Estimated Future Payments Under PPAs [Abstract]
2022		60
2023		61
2024		63
2025		26
2026		9
Thereafter		10
Total	[2]	$ 229
[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, 2021USD ($)
Coal
Fuel Contracts [Abstract]
2022	$ 219
2023	79
2024	48
2025	1
2026	1
Thereafter	1
Total	349	[1]
Nuclear Fuel
Fuel Contracts [Abstract]
2022	89
2023	109
2024	82
2025	119
2026	29
Thereafter	309
Total	737	[1]
Natural Gas Supply
Fuel Contracts [Abstract]
2022	95
2023	0
2024	0
2025	0
2026	0
Thereafter	0
Total	95	[1]
Natural Gas Storage and Transportation
Fuel Contracts [Abstract]
2022	128
2023	114
2024	108
2025	98
2026	97
Thereafter	107
Total	$ 652	[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, 2021	Dec. 31, 2020
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, 2021		Dec. 31, 2020		Dec. 31, 2019
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Accumulated other comprehensive loss at Jan. 1	$ 6,769
Accumulated other comprehensive (loss) income at end of period	7,573		$ 6,769
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	(19)		(20)
Net current period other comprehensive income	2		1
Accumulated other comprehensive (loss) income at end of period	(17)		(19)		(20)
Gains and Losses on Cash Flow Hedges | Interest Rate Swap [Member]
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Interest rate derivatives, net of tax of $—	(2)	[1]	(1)	[2]
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	0		0
Accumulated other comprehensive (loss) income at end of period	(3)		(3)		(3)
Defined Benefit Pension and Postretirement Items | Interest Rate Swap [Member]
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Interest rate derivatives, net of tax of $—	0		0
Total
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Accumulated other comprehensive loss at Jan. 1	(22)		(23)
Net current period other comprehensive income	2		1
Accumulated other comprehensive (loss) income at end of period	(20)		(22)		$ (23)
Total | Interest Rate Swap [Member]
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Interest rate derivatives, net of tax of $—	$ (2)		$ (1)
[1]	Included in interest charges.
[2]	Included in interest charges.

Segments and Related Informat_3

Segments and Related Information (Details) - USD ($) $ in Millions		3 Months Ended								12 Months Ended
		Dec. 31, 2021	Sep. 30, 2021	Jun. 30, 2021	Mar. 31, 2021	Dec. 31, 2020	Sep. 30, 2020	Jun. 30, 2020	Mar. 31, 2020	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Segment Reporting Information [Line Items]
Natural gas										$ 623	$ 493	$ 571
Other										39	37	35
Total operating revenues		$ 1,283	$ 1,388	$ 1,180	$ 1,250	$ 1,283	$ 1,388	$ 1,180	$ 1,250	5,756	5,101	5,112
Depreciation and amortization										926	825	791
Total interest charges and financing costs										258	238	221
Income tax (benefit) expense										(48)	(6)	47
Net income (loss)		$ 121	$ 246	$ 117	$ 107	$ 121	$ 246	$ 117	$ 107	606	591	543
Related Party Transaction - Electric Domestic Regulated Revenue										501	440	457
Related Party Transaction - Gas Domestic Regulated Revenue										1	1	1
Regulated Electricity
Segment Reporting Information [Line Items]
Revenues Including Intersegment Revenues										5,095	4,572	4,507
Depreciation and amortization										869	773	742
Total interest charges and financing costs										240	221	205
Income tax (benefit) expense										(53)	(14)	36
Net income (loss)										566	553	491
Regulated Natural Gas
Segment Reporting Information [Line Items]
Revenues Including Intersegment Revenues										624	493	572
Depreciation and amortization										56	51	49
Total interest charges and financing costs										18	17	16
Income tax (benefit) expense										6	7	12
Net income (loss)										29	30	40
All Other
Segment Reporting Information [Line Items]
Depreciation and amortization										1	1	0
Income tax (benefit) expense										(1)	1	(1)
Net income (loss)										11	8	12
Total revenues
Segment Reporting Information [Line Items]
Total operating revenues	[1],[2]									5,758	5,102	5,114
Total revenues | Regulated Electricity
Segment Reporting Information [Line Items]
Operating revenue, Regulated Electric	[2]									5,094	4,571	4,506
Total revenues | Regulated Natural Gas
Segment Reporting Information [Line Items]
Natural gas	[1]									623	493	571
Total revenues | All Other
Segment Reporting Information [Line Items]
Other										39	37	35
Intersegment Eliminations
Segment Reporting Information [Line Items]
Total operating revenues										(2)	(1)	(2)
Intersegment Eliminations | Regulated Electricity
Segment Reporting Information [Line Items]
Operating revenue, Regulated Electric										1	1	1
Intersegment Eliminations | Regulated Natural Gas
Segment Reporting Information [Line Items]
Natural gas										$ 1	$ 0	$ 1
[1]	Operating revenues include $1 million of affiliate gas revenue for the years ended Dec. 31, 2021, 2020 and 2019, respectively. See Note 13 for further information.
[2]	Operating revenues include $501 million, $440 million and $457 million of affiliate electric revenue for the years ended Dec. 31, 2021, 2020 and 2019, respectively. See Note 13 for further information.

Related Party Transactions (Det

Related Party Transactions (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Operating expenses
Interest expense	$ 0	$ 0	$ 1
Accounts Receivable and Payable with Affiliates [Abstract]
Accounts receivable	29	32
Accounts payable	63	66
NSP-Wisconsin
Accounts Receivable and Payable with Affiliates [Abstract]
Accounts receivable	13	6
Accounts payable	0	0
PSCo
Accounts Receivable and Payable with Affiliates [Abstract]
Accounts receivable	16	1
Accounts payable	0	0
SPS
Accounts Receivable and Payable with Affiliates [Abstract]
Accounts receivable	0	0
Accounts payable	2	3
Other subsidiaries of Xcel Energy Inc.
Accounts Receivable and Payable with Affiliates [Abstract]
Accounts receivable	0	25
Accounts payable	61	63
Purchased Power
Operating expenses
Costs and Expenses, Related Party	67	59	61
Transmission Expense
Operating expenses
Costs and Expenses, Related Party	121	109	116
Other Expense
Operating expenses
Costs and Expenses, Related Party	615	584	533
Electricity, US Regulated
Revenues [Abstract]
Operating Revenue from Related Parties	501	440	457
Natural Gas, US Regulated
Revenues [Abstract]
Operating Revenue from Related Parties	$ 1	$ 1	$ 1

Summarized Quarterly Financia_3

Summarized Quarterly Financial Data (Unaudited) (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2021	Sep. 30, 2021	Jun. 30, 2021	Mar. 31, 2021	Dec. 31, 2020	Sep. 30, 2020	Jun. 30, 2020	Mar. 31, 2020	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Quarterly Financial Information Disclosure [Abstract]
Total operating revenues	$ 1,283	$ 1,388	$ 1,180	$ 1,250	$ 1,283	$ 1,388	$ 1,180	$ 1,250	$ 5,756	$ 5,101	$ 5,112
Operating income	167	314	158	157	167	314	158	157	782	796	787
Net income	$ 121	$ 246	$ 117	$ 107	$ 121	$ 246	$ 117	$ 107	$ 606	$ 591	$ 543

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, 2021	Dec. 31, 2020	Dec. 31, 2019
SEC Schedule, 12-09, Movement in Valuation Allowances and Reserves [Roll Forward]
Balance at Jan. 1		$ 33	$ 23	$ 24
Charged to costs and expenses		24	24	13
Charged to other accounts	[1]	5	5	7
Deductions from reserves	[2]	(17)	(19)	(21)
Balance at Dec. 31		$ 45	$ 33	$ 23
[1]	Recovery of amounts previously written-off.
[2]	Deductions related primarily to bad debt write-offs.