Northern States Power 10-K 26 Feb 18 2017 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2017	Feb. 23, 2018	Jun. 30, 2017
Document and Entity Information [Abstract]
Entity Registrant Name	NORTHERN STATES POWER CO /WI/
Entity Central Index Key	72,909
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Document Type	10-K
Document Period End Date	Dec. 31, 2017
Document Fiscal Year Focus	2,017
Document Fiscal Period Focus	FY
Amendment Flag	false
Entity Common Stock, Shares Outstanding		933,000
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float			$ 0

CONSOLIDATED STATEMENTS OF INCO

CONSOLIDATED STATEMENTS OF INCOME - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Operating revenues
Electric	$ 881,891	$ 849,946	$ 834,998
Natural gas	122,353	106,157	120,147
Other	1,207	1,130	1,396
Total operating revenues	1,005,451	957,233	956,541
Operating expenses
Electric fuel and purchased power, non-affiliates	16,197	15,574	10,795
Purchased power, affiliates	421,609	413,615	419,028
Cost of natural gas sold and transported	62,259	54,436	70,988
Operating and maintenance expenses	205,539	194,927	179,413
Conservation program expenses	12,572	12,645	11,695
Depreciation and amortization	111,216	98,294	91,245
Taxes (other than income taxes)	27,831	27,814	28,181
Loss on Monticello life cycle management/extended power uprate project	0	0	5,237
Total operating expenses	857,223	817,305	816,582
Operating income	148,228	139,928	139,959
Other income, net	833	461	883
Allowance for funds used during construction — equity	6,707	4,277	7,253
Interest charges and financing costs
Interest charges — includes other financing costs of $1,855, $1,854, and $1,738, respectively	35,040	34,452	32,731
Allowance for funds used during construction - debt	(2,860)	(1,823)	(3,510)
Total interest charges and financing costs	32,180	32,629	29,221
Income before income taxes	123,588	112,037	118,874
Income taxes	44,172	42,902	44,238
Net income	$ 79,416	$ 69,135	$ 74,636

CONSOLIDATED STATEMENTS OF INC3

CONSOLIDATED STATEMENTS OF INCOME (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Interest charges and financing costs
Other financing costs	$ 1,855	$ 1,854	$ 1,738

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Comprehensive income:
Net income	$ 79,416	$ 69,135	$ 74,636
Derivative instruments:
Reclassification of losses to net income, net of tax of $50 and $51, and $51, respectively.	76	76	76
Other comprehensive income	76	76	76
Comprehensive income	$ 79,492	$ 69,211	$ 74,712

CONSOLIDATED STATEMENTS OF COM5

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Derivative instruments:
Reclassification of losses to net income, net of tax	$ 50	$ 51	$ 51

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Operating activities
Net income	$ 79,416	$ 69,135	$ 74,636
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	112,750	99,824	92,656
Deferred income taxes	45,557	37,368	45,833
Amortization of investment tax credits	(523)	(523)	(528)
Allowance for equity funds used during construction	(6,707)	(4,277)	(7,253)
Loss on Monticello life cycle management/extended power uprate project	0	0	5,237
Provision for bad debts	4,105	3,730	3,947
Net derivative losses	128	160	482
Other	(1,823)	(623)	0
Changes in operating assets and liabilities:
Accounts receivable	(9,948)	(1,383)	71
Accrued unbilled revenues	(6,370)	(5,940)	5,869
Inventories	552	3,250	3,126
Other current assets	922	(1,191)	7,135
Accounts payable	9,025	10,632	(7,626)
Net regulatory assets and liabilities	(31,223)	(18,601)	(27,114)
Other current liabilities	(2,215)	14,036	5,147
Pension and other employee benefit obligations	(8,558)	(6,197)	(3,177)
Change in other noncurrent assets	583	(718)	209
Change in other noncurrent liabilities	(5,934)	2,050	716
Net cash provided by operating activities	179,737	200,732	199,366
Investing activities
Utility capital/construction expenditures	(218,801)	(204,427)	(251,797)
Allowance for equity funds used during construction	6,707	4,277	7,253
Other, net	(49)	1,198	(224)
Net cash used in investing activities	(212,143)	(198,952)	(244,768)
Financing activities
(Repayments of) proceeds from short-term borrowings, net	(49,000)	50,000	(68,000)
Proceeds from issuance of long-term debt	97,455	0	97,969
Repayments of long-term debt	(77)	(93)	(87)
Capital contributions from parent	47,992	1,935	69,243
Dividends paid to parent	(64,037)	(53,100)	(53,929)
Other, net	(70)	(55)	0
Net cash provided by (used in) financing activities	32,263	(1,313)	45,196
Net change in cash and cash equivalents	(143)	467	(206)
Cash and cash equivalents at beginning of period	1,546	1,079	1,285
Cash and cash equivalents at end of period	1,403	1,546	1,079
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	(30,907)	(30,878)	(27,491)
Cash (paid) received for income taxes, net	(5,046)	5,873	5,762
Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable	$ 27,753	$ 16,172	$ 16,729

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands		Dec. 31, 2017	Dec. 31, 2016
Current assets
Cash and cash equivalents		$ 1,403	$ 1,546
Accounts receivable, net	[1]	63,200	54,031
Accrued unbilled revenues		60,008	53,638
Other receivables		15,144	657
Inventories		17,758	18,309
Regulatory assets		23,113	18,162
Prepaid taxes		23,606	25,915
Prepayments		3,450	3,128
Total current assets		207,682	175,386
Property, plant and equipment, net		2,088,728	1,947,637
Other assets
Regulatory assets		282,217	286,188
Other investments		2,892	2,844
Other		201	785
Total other assets		285,310	289,817
Total assets		2,581,720	2,412,840
Current liabilities
Current portion of long-term debt		151,080	1,123
Short-term debt		11,000	60,000
Notes payable to affiliates		500	500
Accounts payable		58,365	41,068
Accounts payable to affiliates		29,628	29,037
Dividends payable to parent		15,481	10,729
Regulatory liabilities		20,712	17,428
Environmental liabilities		10,469	41,438
Accrued interest		8,025	8,012
Other		34,474	26,484
Total current liabilities		339,734	235,819
Deferred credits and other liabilities
Deferred income taxes		256,687	430,593
Deferred investment tax credits		7,514	8,037
Regulatory liabilities		386,807	148,189
Environmental liabilities		19,190	23,003
Customer advances		16,325	19,425
Pension and employee benefit obligations		50,027	55,164
Other		18,747	18,814
Total deferred credits and other liabilities		755,297	703,225
Commitments and contingencies
Capitalization
Long-term debt		610,100	661,946
Common stock — 1,000,000 shares authorized of $100 par value; 933,000 shares outstanding at Dec. 31, 2017 and 2016, respectively		93,300	93,300
Additional paid in capital		449,350	395,315
Retained earnings		334,008	323,368
Accumulated other comprehensive loss		(69)	(133)
Total common stockholder’s equity		876,589	811,850
Total liabilities and equity		$ 2,581,720	$ 2,412,840
[1]	Accounts receivable, net includes $3.4 million and an immaterial amount due from affiliates for 2017 and 2016, respectively.

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares	Dec. 31, 2017	Dec. 31, 2016
Capitalization
Common stock, shares authorized (in shares)	1,000,000	1,000,000
Common stock, par value (in dollars per share)	$ 100	$ 100
Common stock, shares outstanding (in shares)	933,000	933,000

CONSOLIDATED STATEMENTS OF COMM

CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY - USD ($) $ in Thousands	Total	Common stock	Additional Paid In Capital	Retained Earnings	Accumulated Other Comprehensive Loss
Beginning Balance at Dec. 31, 2014	$ 697,689	$ 93,300	$ 322,276	$ 282,398	$ (285)
Balance (in shares) at Dec. 31, 2014		933,000
Comprehensive income:
Net income	74,636			74,636
Other comprehensive income	76				76
Common dividends declared to parent	(54,293)			(54,293)
Contribution of capital by parent	72,277		72,277
Ending Balance at Dec. 31, 2015	790,385	$ 93,300	394,553	302,741	(209)
Balance (in shares) at Dec. 31, 2015		933,000
Comprehensive income:
Net income	69,135			69,135
Other comprehensive income	76				76
Common dividends declared to parent	(48,508)			(48,508)
Contribution of capital by parent	762		762
Ending Balance at Dec. 31, 2016	$ 811,850	$ 93,300	395,315	323,368	(133)
Balance (in shares) at Dec. 31, 2016	933,000	933,000
Comprehensive income:
Net income	$ 79,416			79,416
Other comprehensive income	76				76
Common dividends declared to parent	(68,788)			(68,788)
Contribution of capital by parent	54,035		54,035
Adoption of ASU No. 2018-02	0			12	(12)
Ending Balance at Dec. 31, 2017	$ 876,589	$ 93,300	$ 449,350	$ 334,008	$ (69)
Balance (in shares) at Dec. 31, 2017	933,000	933,000

CONSOLIDATED STATEMENTS OF CAPI

CONSOLIDATED STATEMENTS OF CAPITALIZATION - USD ($) $ in Thousands		Dec. 31, 2017	Dec. 31, 2016
Schedule of Capitalization, Long-term Debt [Line Items]
Unamortized discount		$ (2,869)	$ (2,865)
Unamortized Debt Issuance Expense		(6,505)	(4,697)
Total long-term debt, including current maturities		761,180	663,069
Less: current maturities		151,080	1,123
Total long-term debt		610,100	661,946
Common Stockholders' Equity
Common stock — 1,000,000 shares authorized of $100 par value; 933,000 shares outstanding at Dec. 31, 2017 and 2016, respectively		93,300	93,300
Additional paid in capital		449,350	395,315
Retained earnings		334,008	323,368
Accumulated other comprehensive loss		(69)	(133)
Total common stockholder’s equity		876,589	811,850
First Mortgage Bonds | Series Due Oct. 1, 2018
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term debt, gross		150,000	150,000
First Mortgage Bonds | Series Due June 15, 2024
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term debt, gross		200,000	200,000
First Mortgage Bonds | Series Due Sept. 1, 2038
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term debt, gross		200,000	200,000
First Mortgage Bonds | Series Due Oct. 1, 2042
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term debt, gross		100,000	100,000
First Mortgage Bonds | Series Due Dec. 1, 2047
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term debt, gross		100,000	0
City of La Crosse Resource Recovery Bond | Series Due Nov. 1, 2021
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term debt, gross	[1]	18,600	18,600
Other
Schedule of Capitalization, Long-term Debt [Line Items]
Long-term debt, gross		$ 1,954	$ 2,031
[1]	Resource recovery financing

CONSOLIDATED STATEMENTS OF CA11

CONSOLIDATED STATEMENTS OF CAPITALIZATION (Parenthetical) - $ / shares	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Common Stockholders Equity [Abstract]
Common stock, shares authorized (in shares)	1,000,000	1,000,000
Common stock, par value (in dollars per share)	$ 100	$ 100
Common stock, shares outstanding (in shares)	933,000	933,000
First Mortgage Bonds | Series Due Oct. 1, 2018
Schedule of Capitalization, Long-term Debt [Line Items]
Debt instrument, interest rate stated percentage (in hundredths)	5.25%	5.25%
Debt instrument, maturity date	Oct. 1, 2018	Oct. 1, 2018
First Mortgage Bonds | Series Due June 15, 2024
Schedule of Capitalization, Long-term Debt [Line Items]
Debt instrument, interest rate stated percentage (in hundredths)	3.30%	3.30%
Debt instrument, maturity date	Jun. 15, 2024	Jun. 15, 2024
First Mortgage Bonds | Series Due Sept. 1, 2038
Schedule of Capitalization, Long-term Debt [Line Items]
Debt instrument, interest rate stated percentage (in hundredths)	6.375%	6.375%
Debt instrument, maturity date	Sep. 1, 2038	Sep. 1, 2038
First Mortgage Bonds | Series Due Oct. 1, 2042
Schedule of Capitalization, Long-term Debt [Line Items]
Debt instrument, interest rate stated percentage (in hundredths)	3.70%	3.70%
Debt instrument, maturity date	Oct. 1, 2042	Oct. 1, 2042
First Mortgage Bonds | Series Due Dec. 1, 2047
Schedule of Capitalization, Long-term Debt [Line Items]
Debt instrument, interest rate stated percentage (in hundredths)	3.75%
Debt instrument, maturity date	Dec. 1, 2047
City of La Crosse Resource Recovery Bond | Series Due Nov. 1, 2021
Schedule of Capitalization, Long-term Debt [Line Items]
Debt instrument, interest rate stated percentage (in hundredths)	6.00%	6.00%
Debt instrument, maturity date	Nov. 1, 2021	Nov. 1, 2021

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2017
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	Summary of Significant Accounting Policies Business and System of Accounts — NSP-Wisconsin is engaged in the regulated generation, transmission, distribution and sale of electricity and in the regulated purchase, transportation, distribution and sale of natural gas. NSP-Wisconsin’s consolidated financial statements and disclosures are presented in accordance with GAAP. All of NSP-Wisconsin’s underlying accounting records also conform to the FERC uniform system of accounts or to systems required by various state regulatory commissions, which are the same in all material respects. Principles of Consolidation — NSP-Wisconsin’s consolidated financial statements include its wholly-owned subsidiaries and variable interest entities for which it is the primary beneficiary. In the consolidation process, all intercompany transactions and balances are eliminated. NSP-Wisconsin has investments in certain transmission facilities jointly owned with nonaffiliated utilities. NSP-Wisconsin’s proportionate share of jointly owned facilities is recorded as property, plant and equipment on the consolidated balance sheets and NSP-Wisconsin’s proportionate share of the operating costs associated with these facilities is included in its consolidated statements of income. See Note 5 for further discussion of jointly owned transmission facilities and related ownership percentages. NSP-Wisconsin evaluates its arrangements and contracts with other entities to determine if the other party is a variable interest entity, if NSP-Wisconsin has a variable interest and if NSP-Wisconsin is the primary beneficiary. NSP-Wisconsin follows accounting guidance for variable interest entities which requires consideration of the activities that most significantly impact an entity’s financial performance and power to direct those activities, when determining whether NSP-Wisconsin is a variable interest entity’s primary beneficiary. See Note 11 for further discussion of variable interest entities. Use of Estimates — In recording transactions and balances resulting from business operations, NSP-Wisconsin uses estimates based on the best information available. Estimates are used for such items 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. The recorded estimates are revised when better information becomes available or when actual amounts can be determined. Those revisions can affect operating results. Regulatory Accounting — NSP-Wisconsin accounts for certain 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 OCI, are deferred as regulatory assets based on the expected ability to recover the costs in future rates; and • Certain credits, which would otherwise be reflected as income or OCI, 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 restructuring or other changes in the regulatory environment occur, NSP-Wisconsin may no longer be eligible to apply this accounting treatment, and may be required to eliminate regulatory assets and liabilities from its balance sheets. Such changes could have a material effect on NSP-Wisconsin’s financial condition, results of operations and cash flows. See Note 12 for further discussion of regulatory assets and liabilities. Revenue Recognition — Revenues related to the sale of energy are generally recorded when service is rendered or energy is delivered to customers. However, the determination of the energy sales to individual customers is based on the reading of their meter, which occurs on a systematic basis 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-Wisconsin presents its revenues net of any excise or other fiduciary-type taxes or fees. NSP-Wisconsin has various rate-adjustment mechanisms in place that provide for the recovery of purchased natural gas, electric fuel and purchased energy costs. These 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, under governing regulatory commission rate orders, 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. Under Wisconsin rules, NSP-Wisconsin must submit a forward looking fuel cost plan annually for approval by the PSCW. The rules also allow for deferral of any under-recovery or over-recovery of fuel costs in excess of a two percent annual tolerance band, for future rate recovery or refund, subject to PSCW approval. Conservation Programs — NSP-Wisconsin participates in and funds conservation programs in its retail jurisdictions to assist customers in conserving energy and reducing peak demand on the electric and natural gas systems. NSP-Wisconsin recovers approved conservation program costs in base rate revenue. For operations in the state of Wisconsin, NSP-Wisconsin is required to contribute 1.2 percent of its three -year average annual operating revenues to the statewide energy efficiency and renewable resource program Focus on Energy. Funding is collected through base rates, and there is no financial incentive provided to the utility. The PSCW has full oversight of Focus on Energy including auditing and verification of programs. The program portfolio is outsourced to a third-party administrator who subcontracts as necessary to implement programs. Property, Plant and Equipment and Depreciation — 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 major 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 also includes costs associated with property held for future use. The depreciable lives of certain plant assets are reviewed annually and revised, if appropriate. 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-Wisconsin records depreciation expense related to its plant using the straight-line method over the plant’s 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. Depreciation expense, expressed as a percentage of average depreciable property, was approximately 3.4 , 3.3 and 3.4 percent for the years ended Dec. 31, 2017, 2016 and 2015, respectively. Leases — NSP-Wisconsin evaluates a variety of contracts for lease classification at inception, including rental arrangements for office space, vehicles and equipment. Contracts determined to contain a lease because of per unit pricing that is other than fixed or market price, terms regarding the use of a particular asset, and other factors are evaluated further to determine if the arrangement is a capital lease. See Note 11 for further discussion of leases. 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 nonoperating income (for equity capital) and interest charges (for debt capital). AFUDC amounts capitalized are included in NSP-Wisconsin’s rate base for establishing utility service rates. Generally, AFUDC costs are recovered from customers as the related property is depreciated. However, in some cases, the PSCW has allowed an AFUDC calculation greater than the FERC-defined AFUDC rate, resulting in higher recognition of AFUDC. In some cases for certain transmission projects, the FERC has approved a more current recovery of the cost of capital associated with large capital projects, resulting in a lower recognition of AFUDC. AROs — NSP-Wisconsin 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. NSP-Wisconsin also recovers through rates certain future plant removal costs in addition to AROs. The accumulated removal costs for these obligations are reflected in the balance sheets as a regulatory liability. See Note 11 for further discussion of AROs. Income Taxes — NSP-Wisconsin accounts for income taxes using the asset and liability method, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the financial statements. NSP-Wisconsin 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-Wisconsin uses the tax 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-Wisconsin’s tax rate changes are generally subject to a normalization method of accounting. Therefore, the revaluation of most its net deferred taxes upon a tax rate reduction results in the establishment of a net regulatory liability which will be refundable to utility customers over the remaining life of the related assets. A tax rate increase would result in the establishment of a similar regulatory asset. 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, the reversal of some temporary differences are accounted for as current income tax expense. 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 certain regulatory assets and liabilities related to income taxes, which are summarized in Note 12. 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. In making such a determination, all available evidence is considered, including scheduled reversals of deferred tax liabilities, projected future taxable income, tax planning strategies and recent financial operations. NSP-Wisconsin 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-Wisconsin 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. NSP-Wisconsin reports interest and penalties related to income taxes within the other income and interest charges sections in the consolidated statements of income. Xcel Energy Inc. and its subsidiaries, including NSP-Wisconsin, file consolidated federal income tax returns as well as combined or separate state income tax returns. Federal income taxes paid by Xcel Energy Inc. are allocated to Xcel Energy Inc.’s subsidiaries based on separate company computations of tax. A similar allocation is made for state income taxes paid by Xcel Energy Inc. in connection with combined state filings. Xcel Energy Inc. also allocates its own income tax benefits to its direct subsidiaries which are recorded directly in equity by the subsidiaries based on the relative positive tax liabilities of the subsidiaries. See Note 6 for further discussion of income taxes. Types of and Accounting for Derivative Instruments — NSP-Wisconsin uses derivative instruments in connection with its utility commodity price and interest rate activities, including forward contracts, futures, swaps and options. All derivative instruments not designated and qualifying for the normal purchases and normal sales exception, as defined by the accounting guidance for derivatives and hedging, are recorded on the consolidated balance sheets at fair value as derivative instruments. This includes certain instruments used to mitigate market risk for the utility operations. The 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. The classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms. Interest rate hedging transactions are recorded as a component of interest expense. NSP-Wisconsin is allowed to recover in electric or natural gas rates the costs of certain financial instruments purchased to reduce commodity cost volatility. For further information on derivatives entered to mitigate commodity price risk on behalf of electric and natural gas customers, see Note 9. Cash Flow Hedges — Certain qualifying hedging relationships are designated as a hedge of a forecasted transaction or future cash flow (cash flow hedge). Changes in the fair value of a derivative designated as a cash flow hedge, to the extent effective, are included in OCI, or deferred as a regulatory asset or liability based on recovery mechanisms until earnings are affected by the hedged transaction. Normal Purchases and Normal Sales — NSP-Wisconsin enters into contracts for the purchase and sale of commodities for use in its business operations. Derivatives and hedging accounting guidance requires a company to evaluate these contracts to determine whether the contracts are derivatives. Certain contracts that meet the definition of a derivative may be exempted from derivative accounting if designated as normal purchases or normal sales. NSP-Wisconsin evaluates all of its contracts at inception to determine if they are derivatives and if they meet the normal purchases and normal sales designation requirements. See Note 9 for further discussion of NSP-Wisconsin’s risk management and derivative activities. Fair Value Measurements — NSP-Wisconsin presents cash equivalents, interest rate derivatives and commodity derivatives 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 as a primary input 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 for an identical contract in an active market, NSP-Wisconsin may use quoted prices for similar contracts, or internally prepared valuation models to determine fair value. For the pension and postretirement plan assets published trading data and pricing models, generally using the most observable inputs available, are utilized to estimate fair value for each security. See Notes 7 and 9 for further discussion. Cash and Cash Equivalents — NSP-Wisconsin considers investments in certain instruments, including commercial paper and money market funds, 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-Wisconsin establishes an allowance for uncollectible receivables based on a policy that reflects its expected exposure to the credit risk of customers. Inventory — All inventory is recorded at average cost. RECs — RECs are marketable environmental instruments that represent proof that energy was generated from eligible renewable energy sources. RECs are awarded upon delivery of the associated energy and can be bought and sold. RECs are typically used as a form of measurement of compliance to RPS enacted by those states that are encouraging construction and consumption from renewable energy sources, but can also be sold separately from the energy produced. NSP-Wisconsin acquires RECs from the generation or purchase of renewable power. When RECs are purchased or acquired in the course of generation they are recorded as inventory at cost. The cost of RECs that are utilized for compliance purposes is recorded as electric fuel and purchased power expense. Sales of RECs that are purchased or acquired in the course of generation are recorded in electric utility operating revenues on a gross basis. The cost of these RECs and related transaction costs are recorded in electric fuel and purchased power expense. Emission Allowances — Emission allowances, including the annual SO 2 and NOx emission allowance entitlement received from the EPA, are recorded at cost plus associated broker commission fees. NSP-Wisconsin follows the inventory accounting model for all emission allowances. Sales of emission allowances are included in electric utility operating revenues and the operating activities section of the consolidated statements of cash flows. Environmental Costs — Environmental costs are recorded when it is probable NSP-Wisconsin 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. If an environmental expense is related to facilities currently in use, such as emission-control equipment, the cost is capitalized and depreciated over the life of the plant. Estimated remediation costs, excluding inflationary increases, are recorded based on experience, an assessment of the current situation and the technology currently available for use in the remediation. The recorded costs are regularly adjusted as estimates are revised and remediation proceeds. If other participating PRPs exist and acknowledge their potential involvement with a site, costs are estimated and recorded only for NSP-Wisconsin’s expected share of the cost. Any future costs of restoring sites where operation may be extended are treated as a capitalized cost of plant retirement. The depreciation expense levels recoverable in rates include a provision for removal expenses, which may include final remediation costs. Removal costs recovered in rates before the related costs are incurred are classified as a regulatory liability. See Note 11 for further discussion of environmental costs. Benefit Plans and Other Postretirement Benefits — NSP-Wisconsin maintains pension and postretirement benefit plans for eligible employees. Recognizing the cost of providing benefits and measuring the projected benefit obligation of these plans under applicable accounting guidance requires management to make various assumptions and estimates. Based on regulatory recovery mechanisms, certain unrecognized actuarial gains and losses and unrecognized prior service costs or credits are recorded as regulatory assets and liabilities, rather than OCI. See Note 7 for further discussion of benefit plans and other postretirement benefits. Guarantees — NSP-Wisconsin recognizes, upon issuance or modification of a guarantee, a liability for the fair market value of the obligation that has been assumed in issuing the guarantee. This liability includes consideration of specific triggering events and other conditions which may modify the ongoing obligation to perform under the guarantee. The obligation recognized is reduced over the term of the guarantee as NSP-Wisconsin is released from risk under the guarantee. See Note 11 for specific details of issued guarantees. Subsequent Events — Management has evaluated the impact of events occurring after Dec. 31, 2017 up to the date of issuance of these consolidated financial statements. These statements contain all necessary adjustments and disclosures resulting from that evaluation.

Accounting Pronouncements

Accounting Pronouncements	12 Months Ended
	Dec. 31, 2017
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]
Accounting Pronouncements	Accounting Pronouncements Recently Issued Revenue Recognition — In May 2014, the FASB issued Revenue from Contracts with Customers, Topic 606 (ASU No. 2014-09) , which provides a new framework for the recognition of revenue. As the appropriate timing of recognition of revenue from contracts with customers in our regulated operations continues to generally be based on the delivery of electricity and natural gas, NSP-Wisconsin’s adoption will primarily result in increased disclosures regarding sources of revenues, including alternative revenue programs. The guidance is effective for interim and annual periods beginning after Dec. 15, 2017. NSP-Wisconsin is implementing the standard on a modified retrospective basis, which requires application to contracts with customers effective Jan. 1, 2018. Classification and Measurement of Financial Instruments — In January 2016, the FASB issued Recognition and Measurement of Financial Assets and Financial Liabilities, Subtopic 825-10 (ASU No. 2016-01), which eliminates the available-for-sale classification for marketable equity securities and also replaces the cost method of accounting for non-marketable equity securities with a model for recognizing impairments and observable price changes. Under the new standard, other than when the consolidation or equity method of accounting is utilized, changes in the fair value of equity securities are to be recognized in earnings. This guidance is effective for interim and annual reporting periods beginning after Dec. 15, 2017. The overall impacts of the Jan. 1, 2018 adoption will not be material. Leases — In February 2016, the FASB issued Leases, Topic 842 (ASU No. 2016-02) , which, for lessees, requires balance sheet recognition of right-of-use assets and lease liabilities for most leases. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, 2018. NSP-Wisconsin has not yet fully determined the impacts of implementation. However, adoption is expected to occur on Jan. 1, 2019 utilizing the practical expedients provided by the standard and proposed in Targeted Improvements, Topic 842 (Proposed ASU 2018-200). As such, agreements entered prior to Jan. 1, 2019 that are currently considered leases are expected to be recognized on the consolidated balance sheet, including contracts for use of office space, equipment and natural gas storage assets, as well as certain purchased power agreements (PPAs) for natural gas-fueled generating facilities. NSP-Wisconsin expects that similar agreements entered after Dec. 31, 2018 will generally qualify as leases under the new standard. Presentation of Net Periodic Benefit Cost — I n March 2017, the FASB issued Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost, Topic 715 (ASU No. 2017-07) , which establishes that only the service cost element of pension cost may be presented as a component of operating income in the income statement. Also under the guidance, only the service cost component of pension cost is eligible for capitalization. As a result of application of accounting principles for rate regulated entities, a similar amount of pension cost, including non-service components, will be recognized consistent with the historical ratemaking treatment and the impacts of adoption will be limited to changes in classification of non-service costs in the consolidated statement of income. This guidance is effective for interim and annual reporting periods beginning after Dec. 15, 2017. Recently Adopted Accounting for the TCJA — In December 2017, the SEC staff issued Staff Accounting Bulletin No. 118 Income Tax Accounting Implications of the Tax Cuts and Jobs Act (SAB 118), to supplement the accounting requirements of ASC Topic 740 Income Taxes (ASC Topic 740) as it relates to assessing and recognizing the impacts of the TCJA in the period of enactment. SAB 118 allows an entity to recognize provisional amounts in its financial statements in circumstances in which the entity’s assessment is incomplete, but for which a reasonable estimate can be made. Provisional amounts recognized are subject to adjustment for up to one year from the enactment date. For further details, see Note 6 to the consolidated financial statements. Reporting Comprehensive Income — In February 2018, the FASB issued Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income, Topic 220 (ASU No. 2018-02), which addresses the stranded amounts of accumulated OCI which may result from enactment of a new tax law. Though accumulated OCI is presented on a net-of-tax basis, ASC Topic 740 requires that the effects of new tax laws on items in accumulated OCI be recognized without a corresponding adjustment to accumulated OCI, and instead recorded to income tax expense. ASU No. 2018-02 permits stranded amounts of accumulated OCI specifically resulting from the TCJA to be removed from accumulated OCI and reclassified to retained earnings, if elected. NSP-Wisconsin adopted the guidance in the fourth quarter of 2017, and elected to recognize an immaterial increase to accumulated other comprehensive loss and retained earnings in the consolidated financial statements for the year ended Dec. 31, 2017, related to a revaluation of deferred income tax assets and liabilities for items in accumulated other comprehensive loss, at the TCJA federal tax rate.

Selected Balance Sheet Data

Selected Balance Sheet Data	12 Months Ended
	Dec. 31, 2017
Balance Sheet Related Disclosures [Abstract]
Selected Balance Sheet Data	Selected Balance Sheet Data (Thousands of Dollars) Dec. 31, 2017 Dec. 31, 2016 Accounts receivable, net (a) Accounts receivable $ 68,073 $ 58,896 Less allowance for bad debts (4,873 ) (4,865 ) $ 63,200 $ 54,031 (a) Accounts receivable, net includes $3.4 million and an immaterial amount due from affiliates for 2017 and 2016, respectively. (Thousands of Dollars) Dec. 31, 2017 Dec. 31, 2016 Inventories Materials and supplies $ 6,916 $ 6,582 Fuel 3,866 4,743 Natural gas 6,976 6,984 $ 17,758 $ 18,309 (Thousands of Dollars) Dec. 31, 2017 Dec. 31, 2016 Property, plant and equipment, net Electric plant $ 2,602,671 $ 2,499,401 Natural gas plant 326,723 294,986 Common and other property 181,105 156,316 CWIP 148,770 118,822 Total property, plant and equipment 3,259,269 3,069,525 Less accumulated depreciation (1,170,541 ) (1,121,888 ) $ 2,088,728 $ 1,947,637

Borrowings and Other Financing

Borrowings and Other Financing Instruments	12 Months Ended
	Dec. 31, 2017
Debt Disclosure [Abstract]
Borrowings and Other Financing Instruments	Borrowings and Other Financing Instruments Commercial Paper — NSP-Wisconsin meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under its credit facility. Commercial paper outstanding for NSP-Wisconsin was as follows: (Amounts in Millions, Except Interest Rates) Three Months Ended Dec. 31, 2017 Borrowing limit $ 150 Amount outstanding at period end 11 Average amount outstanding 70 Maximum amount outstanding 129 Weighted average interest rate, computed on a daily basis 1.38 % Weighted average interest rate at period end 1.73 (Amounts in Millions, Except Interest Rates) Twelve Months Ended Dec. 31, 2017 Twelve Months Ended Dec. 31, 2016 Twelve Months Ended Dec. 31, 2015 Borrowing limit $ 150 $ 150 $ 150 Amount outstanding at period end 11 60 10 Average amount outstanding 52 15 39 Maximum amount outstanding 129 64 122 Weighted average interest rate, computed on a daily basis 1.23 % 0.69 % 0.44 % Weighted average interest rate at period end 1.73 0.95 0.70 Letters of Credit — NSP-Wisconsin may use letters of credit, generally with terms of one -year, to provide financial guarantees for certain operating obligations. At Dec. 31, 2017 and 2016 , there were no letters of credit outstanding. Credit Facility — In order to use its commercial paper program to fulfill short-term funding needs, NSP-Wisconsin must have a revolving credit facility in place at least equal to the amount of its commercial paper borrowing limit and cannot issue commercial paper in an aggregate amount exceeding available capacity under this credit facility. The line of credit provides short-term financing in the form of notes payable to banks, letters of credit and back-up support for commercial paper borrowings. NSP-Wisconsin has the right to request an extension of the June 2021 termination date for an additional one -year period. The extension requests are subject to majority bank group approval. Other features of NSP-Wisconsin’s credit facility include: • The credit facility has a financial covenant requiring that the debt-to-total capitalization ratio be less than or equal to 65 percent . NSP-Wisconsin was in compliance as its debt-to-total capitalization ratio was 47 percent at both Dec. 31, 2017 and 2016. If NSP-Wisconsin 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. • The credit facility has a cross-default provision that provides NSP-Wisconsin will be in default on its borrowings under the facility if NSP-Wisconsin or any of its subsidiaries whose total assets exceed 15 percent of NSP-Wisconsin’s consolidated total assets, default on certain indebtedness in an aggregate principal amount exceeding $75 million . • NSP-Wisconsin was in compliance with all financial covenants on its debt agreements as of Dec. 31, 2017 and 2016. At Dec. 31, 2017 , NSP-Wisconsin had the following committed credit facility available (in millions): Credit Facility (a) Drawn (b) Available $ 150 $ 11 $ 139 (a) This credit facility matures in June 2021 . (b) Includes outstanding commercial paper. All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity under the credit facility. NSP-Wisconsin had no direct advances on the credit facility outstanding at Dec. 31, 2017 and 2016 . Other Short-Term Borrowings — The following table presents the notes payable of Clearwater Investments, Inc., a NSP-Wisconsin subsidiary, to Xcel Energy Inc.: (Amounts in Millions, Except Interest Rates) Dec. 31, 2017 Dec. 31, 2016 Notes payable to affiliates $ 0.5 $ 0.5 Weighted average interest rate 1.73 % 0.95 % Long-Term Borrowings and Other Financing Instruments Generally, all real and personal property of NSP-Wisconsin is subject to the liens of its first mortgage indentures. Debt premiums, discounts and expenses are amortized over the life of the related debt. The premiums, discounts and expenses associated with refinanced debt are deferred and amortized over the life of the related new issuance, in accordance with regulatory guidelines. In 2017, NSP-Wisconsin issued $100 million of 3.75 percent first mortgage bonds due Dec. 1, 2047 . During the next five years, NSP-Wisconsin has long-term debt maturities of approximately $151 million , $19 million and $1 million due in 2018, 2021 and 2022, respectively. Deferred Financing Costs — Deferred financing costs of approximately $7 million and $5 million , net of amortization, are presented as a deduction from the carrying amount of long-term debt at Dec. 31, 2017 and 2016 , respectively. NSP-Wisconsin is amortizing these financing costs over the remaining maturity periods of the related debt. Dividend Restrictions — NSP-Wisconsin’s dividends are subject to the FERC’s jurisdiction, which prohibits the payment of dividends out of capital accounts; payment of dividends is allowed out of retained earnings only. The most restrictive dividend limitation for NSP-Wisconsin is imposed by its state regulatory commission. NSP-Wisconsin cannot pay annual dividends in excess of approximately $53 million if its calendar year average equity-to-total capitalization ratio is or falls below the state commission authorized level as calculated consistent with PSCW requirements. NSP-Wisconsin’s calendar year average equity-to-total capitalization ratio calculated on this basis was 53.1 percent at Dec. 31, 2017 and $19 million in retained earnings was not restricted. NSP-Wisconsin’s authorized equity ratio was 52.5 percent for 2016 and 2017, but will be 51.5 percent for 2018.

Joint Ownership of Transmission

Joint Ownership of Transmission Facilities	12 Months Ended
	Dec. 31, 2017
Joint Ownership of Transmission Facilities [Abstract]
Joint Ownership of Transmission Facilities	Joint Ownership of Transmission Facilities Following are the investments by NSP-Wisconsin in jointly owned transmission facilities and the related ownership percentages as of Dec. 31, 2017 : (Thousands of Dollars) Plant in Accumulated Depreciation CWIP Ownership % Electric Transmission: CapX2020 Transmission $ 162,108 $ 12,205 $ 103,144 81 % La Crosse, Wis. to Madison, Wis. — — 101,546 37 Total $ 162,108 $ 12,205 $ 204,690 NSP-Wisconsin’s share of operating expenses and construction expenditures are included in the applicable utility accounts. Each of the respective owners is responsible for providing its own financing.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Income Taxes	Income Taxes Federal Tax Reform — In December 2017, the TCJA was signed into law. While the legislation will require interpretations and regulations to be issued by the IRS, the key provisions impacting Xcel Energy (which includes NSP-Wisconsin) generally beginning in 2018, include: • Corporate federal tax rate reduction from 35 percent to 21 percent ; • Normalization of resulting plant-related excess deferred taxes; • Elimination of the corporate alternative minimum tax; • Continued interest expense deductibility and discontinued bonus depreciation for regulated public utilities; • Limitations on certain executive compensation deductions; • Limitations on certain deductions for NOLs arising after Dec. 31, 2017 (limited to 80 percent of taxable income); • Repeal of the section 199 manufacturing deduction; and • Reduced deductions for meals and entertainment as well as state and local lobbying. Entities are required under ASC Topic 740 to recognize the accounting impacts of a tax law change, including the impacts of a change in tax rates on deferred tax assets and liabilities, in the period including the date of the tax law enactment. The SEC staff issued guidance in SAB 118 that supplements the accounting requirements of ASC Topic 740 if elements of the TCJA assessment are not complete, and provides for up to a one year period to finalize the required accounting. Xcel Energy has estimated the effects of the TCJA, which have been reflected in the Dec. 31, 2017 consolidated financial statements. Issuance of U.S. Treasury regulations interpreting the TCJA, other U.S. Treasury and IRS guidance or interpretations of the application of ASC Topic 740 may result in changes to these estimates. Overall for Xcel Energy, reductions in deferred tax assets and liabilities due to the reduction in corporate federal tax rates result in a net tax benefit. However, as a result of IRS requirements and past regulatory treatment of deferred taxes in the determination of regulated rates of the utility subsidiaries, including deferred taxes related to regulated plant and certain other deferred tax assets and liabilities, the impact was primarily recognized as a regulatory liability refundable to utility customers. The fourth quarter 2017 estimated accounting impacts of the December 2017 enactment of the new tax law at NSP-Wisconsin included: • $149 million ( $210 million grossed-up for tax) of reclassifications of plant-related excess deferred taxes to regulatory liabilities upon valuation at the new 21 percent federal rate. The regulatory liabilities will be amortized consistent with IRS normalization requirements, resulting in customer refunds over the average remaining life of the related property; • $23 million and $41 million of reclassifications (grossed-up for tax) of excess deferred taxes for non-plant related deferred tax assets and liabilities, respectively, to regulatory assets and liabilities; • An immaterial income tax benefit related to the federal tax reform implementation, and a $1 million reduction to net income related to the allocation of Xcel Energy Services Inc.’s tax rate change on its deferred taxes. Xcel Energy has accounted for the state tax impacts of federal tax reform based on currently enacted state tax laws. Any future state tax law changes related to the TCJA will be accounted for in the periods state laws are enacted. Consolidated Appropriations Act, 2016 — In December 2015, the Consolidated Appropriations Act, 2016 (Act) was signed into law. The Act provided for the following: • Immediate expensing, or “bonus depreciation,” of 50 percent for property placed in service in 2015, 2016, and 2017; • PTCs at 100 percent of the applicable rate for wind energy projects that begin construction by the end of 2016; 80 percent of the credit rate for projects that begin construction in 2017; 60 percent of the credit rate for projects that begin construction in 2018; and 40 percent of the credit rate for projects that begin construction in 2019. The wind energy PTC was not extended for projects that begin construction after 2019; • ITCs at 30 percent for commercial solar projects that begin construction by the end of 2019; 26 percent for projects that begin construction in 2020; 22 percent for projects that begin construction in 2021; and 10 percent for projects thereafter; • R&E credit was permanently extended; and • Delay of two years (until 2020) of the excise tax on certain employer-provided health insurance plans. The accounting related to the Act was recorded beginning in the fourth quarter of 2015 because a change in tax law is accounted for beginning in the period of enactment. Federal Audit — NSP-Wisconsin is a member of the Xcel Energy affiliated group that files a consolidated federal income tax return. The statutes of limitations applicable to Xcel Energy’s federal income tax returns expire as follows: Tax Year(s) Expiration 2009 - 2011 June 2018 2012 - 2013 October 2018 2014 September 2018 2015 September 2019 2016 September 2020 In 2012, the IRS commenced an examination of tax years 2010 and 2011 , including the 2009 carryback claim. The IRS proposed an adjustment to the federal tax loss carryback claims that would have resulted in $14 million of income tax expense for the 2009 through 2011 claims, and the 2013 through 2015 claims. In the fourth quarter of 2015, the IRS forwarded the issue to the Office of Appeals (“Appeals”). In the third quarter of 2017, Xcel Energy and Appeals reached an agreement and the benefit related to the agreed upon portions was recognized. NSP-Wisconsin did not accrue any income tax benefit related to this adjustment. As of Dec. 31, 2017, the case has been forwarded to the Joint Committee on Taxation. In the third quarter of 2015, the IRS commenced an examination of tax years 2012 and 2013 . In the third quarter of 2017, the IRS concluded the audit of tax years 2012 and 2013 and proposed an adjustment that would impact Xcel Energy’s NOL and ETR. After evaluating the proposed adjustment, Xcel Energy filed a protest with the IRS. Xcel Energy anticipates the issue will be forwarded to Appeals. As of Dec, 31, 2017, 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 uncertain. State Audits — NSP-Wisconsin is a member of the Xcel Energy affiliated group that files consolidated state income tax returns. As of Dec. 31, 2017, NSP-Wisconsin’s earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations is 2012 . In 2016, the state of Wisconsin began an audit of years 2012 and 2013 . As of Dec. 31, 2017, Wisconsin had not proposed any material adjustments, and there were no other state income tax audits in progress. Unrecognized Tax Benefits — The unrecognized tax benefit balance includes permanent tax positions, which if recognized would affect the annual ETR. In addition, the unrecognized tax benefit balance includes temporary tax positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. A change in the period of deductibility would not affect the ETR but would accelerate the payment of cash to the taxing authority to an earlier period. A reconciliation of the amount of unrecognized tax benefit is as follows: (Millions of Dollars) Dec. 31, 2017 Dec. 31, 2016 Unrecognized tax benefit — Permanent tax positions $ 1.4 $ 0.4 Unrecognized tax benefit — Temporary tax positions 1.0 4.9 Total unrecognized tax benefit $ 2.4 $ 5.3 A reconciliation of the beginning and ending amount of unrecognized tax benefit is as follows: (Millions of Dollars) 2017 2016 2015 Balance at Jan. 1 $ 5.3 $ 4.5 $ 3.0 Additions based on tax positions related to the current year 0.4 0.5 1.9 Reductions based on tax positions related to the current year (0.3 ) — (0.3 ) Additions for tax positions of prior years 1.3 0.5 0.8 Reductions for tax positions of prior years (4.3 ) (0.2 ) (0.9 ) Balance at Dec. 31 $ 2.4 $ 5.3 $ 4.5 The unrecognized tax benefit amounts were reduced by the tax benefits associated with NOL and tax credit carryforwards. The amounts of tax benefits associated with NOL and tax credit carryforwards are as follows: (Millions of Dollars) Dec. 31, 2017 Dec. 31, 2016 NOL and tax credit carryforwards $ (1.9 ) $ (1.2 ) It is reasonably possible that NSP-Wisconsin’s amount of unrecognized tax benefits could significantly change in the next 12 months as the IRS Appeals progresses and audit resumes, the Wisconsin audit progresses, and other state audits resume. As the IRS Appeals and Wisconsin audit progress, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $1 million . The payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryforwards. The payables for interest related to unrecognized tax benefits at Dec. 31, 2017, 2016 and 2015 were not material. No amounts were accrued for penalties related to unrecognized tax benefits as of Dec. 31, 2017, 2016 or 2015. Other Income Tax Matters — NOL amounts represent the amount of 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) 2017 2016 Federal NOL carryforward $ 58 $ 97 Federal tax credit carryforwards 4 4 State NOL carryforward 5 3 The federal carryforward periods expire between 2021 and 2037 . The state carryforward periods expire between 2021 and 2032 . Total income tax expense from operations differs from the amount computed by applying the statutory federal income tax rate to income before income tax expense. The following reconciles such differences for the years ending Dec. 31: 2017 2016 (b) 2015 (b) Federal statutory rate 35.0 % 35.0 % 35.0 % State income tax on pretax income, net of federal tax effect 5.1 % 5.1 % 5.1 % Increases (decreases) in tax from: Adjustments attributable to tax returns (2.3 ) (0.3 ) (0.4 ) Regulatory differences - effects of rate changes (a) (0.1 ) (0.2 ) (0.2 ) Regulatory differences - other utility plant items (1.7 ) (0.6 ) (1.8 ) Tax credits recognized, net of federal income tax expense (1.0 ) (0.7 ) (0.7 ) Change in unrecognized tax benefits 0.8 0.1 0.1 Other, net (0.1 ) (0.1 ) 0.1 Effective income tax rate 35.7 % 38.3 % 37.2 % (a) The amortization of excess deferred taxes. (b) The prior periods included in this footnote have been reclassified to conform to current year presentation. The components of income tax expense for the years ending Dec. 31 were: (Thousands of Dollars) 2017 2016 2015 Current federal tax expense (benefit) $ 2,765 $ 5,367 $ (4,715 ) Current state tax (benefit) expense (1 ) 131 2,150 Current change in unrecognized tax (benefit) expense (3,626 ) 559 1,498 Deferred federal tax expense 32,919 29,588 40,580 Deferred state tax expense 7,972 8,212 6,675 Deferred change in unrecognized tax expense (benefit) 4,666 (432 ) (1,422 ) Deferred investment tax credits (523 ) (523 ) (528 ) Total income tax expense $ 44,172 $ 42,902 $ 44,238 The components of deferred income tax expense for the years ending Dec. 31 were: (Thousands of Dollars) 2017 2016 2015 Deferred tax (benefit) expense excluding items below $ (173,906 ) $ 39,530 $ 51,084 Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities 219,514 (2,112 ) (5,200 ) Tax expense allocated to other comprehensive income, net of adoption of ASU No. 2018-02, and other (51 ) (50 ) (51 ) Deferred tax expense $ 45,557 $ 37,368 $ 45,833 The components of the net deferred tax liability at Dec. 31 were as follows: (Thousands of Dollars) 2017 2016 (a) Deferred tax liabilities: Difference between book and tax bases of property $ 270,425 $ 412,071 Regulatory assets 58,436 63,825 Pension expense 14,245 21,575 Other 6,855 9,666 Total deferred tax liabilities $ 349,961 $ 507,137 Deferred tax assets: Regulatory liabilities $ 55,768 $ (5,788 ) NOL carryforward 12,606 35,216 Environmental remediation 8,068 25,842 Tax credit carryforward 4,644 3,704 Other employee benefits 3,868 6,132 Deferred investment tax credits 3,175 4,996 Other 5,145 6,442 Total deferred tax assets $ 93,274 $ 76,544 Net deferred tax liability $ 256,687 $ 430,593 (a) The prior period included in this footnote has been reclassified to conform to current year presentation.

Benefit Plans and Other Postret

Benefit Plans and Other Postretirement Benefits	12 Months Ended
	Dec. 31, 2017
Retirement Benefits [Abstract]
Benefit Plans and Other Postretirement Benefits	Benefit Plans and Other Postretirement Benefits Consistent with the process for rate recovery of pension and postretirement benefits for its employees, NSP-Wisconsin accounts for its participation in, and related costs of, pension and other postretirement benefit plans sponsored by Xcel Energy Inc. as multiple employer plans. NSP-Wisconsin is responsible for its share of cash contributions, plan costs and obligations and is entitled to its share of plan assets; accordingly, NSP-Wisconsin accounts for its pro rata share of these plans, including pension expense and contributions, resulting in accounting consistent with that of a single employer plan exclusively for NSP-Wisconsin employees. Xcel Energy, which includes NSP-Wisconsin, offers various benefit plans to its employees. Approximately 71 percent of employees that receive benefits are represented by several local labor unions under several collective-bargaining agreements. At Dec. 31, 2017, NSP-Wisconsin had 383 bargaining employees covered under a collective-bargaining agreement, which expires in December 2019. The plans invest in various instruments which are disclosed under the accounting guidance for fair value measurements which establishes a hierarchical framework for disclosing the observability of the inputs utilized in measuring fair value. The three levels in the hierarchy and examples of each level are as follows: Level 1 — Quoted prices are available in active markets for identical assets as of the reporting date. The types of assets 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 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 included in Level 3 are those with inputs requiring significant management judgment or estimation. Specific valuation methods include the following: Cash equivalents — The fair values of cash equivalents are generally based on cost plus accrued interest; money market funds are measured using quoted NAVs. Insurance contracts — Insurance contract fair values take into consideration the value of the investments in separate accounts of the insurer, which are priced based on observable inputs. Investments in commingled funds, 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, which take into consideration the value of underlying fund investments, as well as the other accrued assets and liabilities of a fund, in order to determine a per share market value. The investments in commingled funds may be redeemed for NAV with proper notice. Proper notice varies by fund and can range from daily with a few days’ notice to annually with 90 days ’ notice. Private equity 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. Depending on the fund, unscheduled distributions from real estate investments may require approval of the fund or may be redeemed with proper notice, which is typically quarterly with 45 - 90 days ’ notice; however, withdrawals from real estate investments 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. Derivative Instruments — Fair values for foreign currency derivatives are determined using pricing models based on the prevailing forward exchange rate of the underlying currencies. The fair values of interest rate derivatives are based on broker quotes that utilize current market interest rate forecasts. Pension Benefits Xcel Energy, which includes NSP-Wisconsin, has several noncontributory, defined benefit pension plans that cover almost all employees. Generally, benefits are based on a combination of years of service, the employee’s average pay and, in some cases, social security benefits. Xcel Energy Inc.’s and NSP-Wisconsin’s policy is to fully fund into an external trust the actuarially determined pension costs recognized for ratemaking and financial reporting purposes, subject to the limitations of applicable employee benefit and tax laws. In addition to the qualified pension plans, Xcel Energy maintains a supplemental executive retirement plan (SERP) and a nonqualified pension plan. The SERP is maintained for certain executives that were participants in the plan in 2008, when the SERP was closed to new participants. The nonqualified pension plan provides unfunded, nonqualified benefits for compensation that is in excess of the limits applicable to the qualified pension plans, with distributions attributable to NSP-Wisconsin funded by NSP-Wisconsin’s consolidated operating cash flows. The total obligations of the SERP and nonqualified plan as of Dec. 31, 2017 and 2016 were $37 million and $44 million , respectively, of which $1 million was attributable to NSP-Wisconsin in both 2017 and 2016. In 2017 and 2016, Xcel Energy recognized net benefit cost for financial reporting for the SERP and nonqualified plans of $5 million and $8 million , respectively, of which amounts attributable to NSP-Wisconsin were immaterial. In 2016, Xcel Energy established rabbi trusts to provide partial funding for future distributions of the SERP and its deferred compensation plan. Rabbi trust funding of deferred compensation plan distributions attributable to NSP-Wisconsin will be supplemented by NSP-Wisconsin’s consolidated operating cash flows as determined necessary. The amount of rabbi trust funding attributable to NSP-Wisconsin is immaterial. Also in 2016, Xcel Energy amended the deferred compensation plan to provide eligible participants the ability to diversify deferred settlements of equity awards, other than time-based equity awards, into various fund options. Xcel Energy Inc. and NSP-Wisconsin base the investment-return assumption on expected long-term performance for each of the investment types included in the pension asset portfolio and consider the historical returns achieved by the asset portfolio over the past 20 -year or longer period, as well as the long-term return levels projected and recommended by investment experts. Xcel Energy Inc. and NSP-Wisconsin continually review pension assumptions. The pension cost determination assumes a forecasted mix of investment types over the long term. • Investment returns in 2017 were above the assumed level of 7.10 percent ; • Investment returns in 2016 were below the assumed level of 7.10 percent ; • Investment returns in 2015 were below the assumed level of 7.25 percent ; and • In 2018, NSP-Wisconsin’s expected investment-return assumption is 7.10 percent . The assets are invested in a portfolio according to Xcel Energy Inc.’s and NSP-Wisconsin’s return, liquidity and diversification objectives to provide funding for plan obligations and minimize contributions to the plan, within appropriate levels of risk. The principal mechanism for achieving these objectives is the projected asset allocation given the long-term risk, return, and liquidity characteristics of each particular asset class. There were no significant concentrations of risk in any particular industry, index, or entity. Market volatility can impact even well-diversified portfolios and significantly affect the return levels achieved by pension assets in any year. The following table presents the target pension asset allocations for NSP-Wisconsin at Dec. 31 for the upcoming year: 2017 2016 Domestic and international equity securities 38 % 40 % Long-duration fixed income and interest rate swap securities 23 23 Short-to-intermediate fixed income securities 21 16 Alternative investments 16 19 Cash 2 2 Total 100 % 100 % The 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. The aggregate projected asset allocation presented in the table above for the master pension trust results from the plan-specific strategies. Pension Plan Assets The following tables present, for each of the fair value hierarchy levels, NSP-Wisconsin’s pension plan assets that are measured at fair value as of Dec. 31, 2017 and 2016 : Dec. 31, 2017 (Thousands of Dollars) Level 1 Level 2 Level 3 Investments Measured at NAV Total Cash equivalents $ 8,091 $ — $ — $ — $ 8,091 Commingled funds: U.S. equity funds 21,850 — — — 21,850 Non U.S. equity funds 3,900 — — 8,479 12,379 U.S. corporate bond funds 14,035 — — — 14,035 Emerging market equity funds — — — 13,381 13,381 Emerging market debt funds 3,198 — — 7,079 10,277 Private equity investments — — — 3,583 3,583 Real estate — — — 8,309 8,309 Other commingled funds 206 — — 4,965 5,171 Debt securities: Government securities — 12,167 — — 12,167 U.S. corporate bonds — 10,178 — — 10,178 Non U.S. corporate bonds — 1,730 — — 1,730 Equity securities: U.S. equities 4,863 — — — 4,863 Other (1,334 ) 149 — 23 (1,162 ) Total $ 54,809 $ 24,224 $ — $ 45,819 $ 124,852 Dec. 31, 2016 (Thousands of Dollars) Level 1 Level 2 Level 3 Investments Measured at NAV Total Cash equivalents $ 3,939 $ — $ — $ — $ 3,939 Commingled funds: U.S. equity funds 21,415 — — — 21,415 Non U.S. equity funds 7,406 — — 8,942 16,348 U.S. corporate bond funds 10,581 — — — 10,581 Emerging market equity funds — — — 8,577 8,577 Emerging market debt funds 3,519 — — 3,787 7,306 Commodity funds — — — 889 889 Private equity investments — — — 4,652 4,652 Real estate — — — 8,108 8,108 Other commingled funds — — — 8,752 8,752 Debt securities: Government securities — 12,773 — — 12,773 U.S. corporate bonds — 9,432 — — 9,432 Non U.S. corporate bonds — 1,514 — — 1,514 Mortgage-backed securities — 254 — — 254 Asset-backed securities — 120 — — 120 Equity securities: U.S. equities 4,219 — — — 4,219 Other — 97 — — 97 Total $ 51,079 $ 24,190 $ — $ 43,707 $ 118,976 There were no assets transferred in or out of Level 3 for the years ended Dec. 31, 2017, 2016 or 2015. Benefit Obligations — A comparison of the actuarially computed pension benefit obligation and plan assets for NSP-Wisconsin is presented in the following table: (Thousands of Dollars) 2017 2016 Accumulated Benefit Obligation at Dec. 31 $ 145,387 $ 146,448 Change in Projected Benefit Obligation: Obligation at Jan. 1 $ 157,457 $ 152,545 Service cost 4,618 4,417 Interest cost 6,218 6,816 Plan amendments (713 ) 305 Actuarial loss 6,499 7,315 Benefit payments (a) (17,331 ) (13,941 ) Obligation at Dec. 31 $ 156,748 $ 157,457 (Thousands of Dollars) 2017 2016 Change in Fair Value of Plan Assets: Fair value of plan assets at Jan. 1 $ 118,976 $ 119,314 Actual return on plan assets 13,923 6,163 Employer contributions 9,284 7,440 Benefit payments (a) (17,331 ) (13,941 ) Fair value of plan assets at Dec. 31 $ 124,852 $ 118,976 (Thousands of Dollars) 2017 2016 Funded Status of Plans at Dec. 31: Funded status (b) $ (31,896 ) $ (38,481 ) (a) 2017 amount includes approximately $13 million of lump-sum benefit payments used in the determination of a settlement charge. (b) Amounts are recognized in noncurrent liabilities on NSP-Wisconsin’s consolidated balance sheets. (Thousands of Dollars) 2017 2016 Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost: Net loss $ 80,429 $ 91,531 Prior service (credit) cost (346 ) 750 Total $ 80,083 $ 92,281 (Thousands of Dollars) 2017 2016 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 $ 5,548 $ 5,972 Noncurrent regulatory assets 74,535 86,309 Total $ 80,083 $ 92,281 Measurement date Dec. 31, 2017 Dec. 31, 2016 2017 2016 Significant Assumptions Used to Measure Benefit Obligations: Discount rate for year-end valuation 3.63 % 4.13 % Expected average long-term increase in compensation level 3.75 3.75 Mortality table RP 2014 RP 2014 Mortality — In 2014, the Society of Actuaries published a new mortality table (RP-2014) that increased the overall life expectancy of males and females. In 2014, NSP-Wisconsin adopted this mortality table, with modifications, based on its population and specific experience. During 2017, a new projection table was released (MP-2017). NSP-Wisconsin evaluated the updated projection table and concluded that the methodology currently in use and adopted in 2016 is consistent with the recently updated 2017 table and continues to be representative of NSP-Wisconsin’s population. Cash Flows — Cash funding requirements can be impacted by changes to actuarial assumptions, actual asset levels and other calculations prescribed by the funding requirements of income tax and other pension-related regulations. Required contributions were made in 2015 through 2018 to meet minimum funding requirements. Total voluntary and required pension funding contributions across all four of Xcel Energy’s pension plans were as follows: • $150 million in January 2018, of which $10 million was attributable to NSP-Wisconsin; • $162 million in 2017, of which $9 million was attributable to NSP-Wisconsin; • $125 million in 2016, of which $7 million was attributable to NSP-Wisconsin; and • $90 million in 2015, of which $5 million was attributable to NSP-Wisconsin. For future years, Xcel Energy and NSP-Wisconsin anticipate contributions will be made as necessary. Plan Amendments — Xcel Energy, which includes NSP-Wisconsin, amended the Xcel Energy Pension Plan in 2017 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. In 2016, the Xcel Energy Pension Plan was amended to change the discount rate basis for lump-sum conversion to annuity participants and annuity conversion to lump-sum participants. Benefit Costs — The components of NSP-Wisconsin’s net periodic pension cost were: (Thousands of Dollars) 2017 2016 2015 Service cost $ 4,618 $ 4,417 $ 4,759 Interest cost 6,218 6,816 6,520 Expected return on plan assets (9,180 ) (9,157 ) (9,483 ) Amortization of prior service cost 138 111 111 Amortization of net loss 5,846 5,392 6,804 Settlement charge (a) 7,107 — — Net periodic pension cost 14,747 7,579 8,711 Costs not recognized due to effects of regulation (4,176 ) — — Net benefit cost recognized for financial reporting $ 10,571 $ 7,579 $ 8,711 (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 the fourth quarter of 2017 as a result of lump-sum distributions during the 2017 plan year, NSP-Wisconsin recorded a total pension settlement charge of $7 million , the majority of which was not recognized due to the effects of regulation. A total of $2 million of that amount was recorded in O&M expenses in the fourth quarter of 2017. 2017 2016 2015 Significant Assumptions Used to Measure Costs: Discount rate 4.13 % 4.66 % 4.11 % Expected average long-term increase in compensation level 3.75 4.00 3.75 Expected average long-term rate of return on assets 7.10 7.10 7.25 In addition to the benefit costs in the table above, for the pension plans sponsored by Xcel Energy Inc., costs are allocated to NSP-Wisconsin based on Xcel Energy Services Inc. employees’ labor costs. The amount allocated to NSP-Wisconsin was $3 million , $2 million and $2 million in 2017, 2016 and 2015, respectively. Pension costs include an expected return impact for the current year that may differ from actual investment performance in the plan. The return assumption used for 2018 pension cost calculations is 7.10 percent . The cost calculation uses a market-related valuation of pension assets. Xcel Energy, including NSP-Wisconsin, uses a calculated value method to determine the market-related value of the plan assets. The market-related value begins with the fair market value of assets as of the beginning of the year. The market-related value is determined by adjusting the fair market value of assets to reflect the investment gains and losses (the difference between the actual investment return and the expected investment return on the market-related value) during each of the previous five years at the rate of 20 percent per year. As these differences between actual investment returns and the expected investment returns are incorporated into the market-related value, the differences are recognized over the expected average remaining years of service for active employees. Defined Contribution Plans Xcel Energy, which includes NSP-Wisconsin, maintains 401(k) and other defined contribution plans that cover substantially all employees. The expense to these plans for NSP-Wisconsin was approximately $1 million in 2017, 2016 and 2015. Postretirement Health Care Benefits Xcel Energy, which includes NSP-Wisconsin, has a contributory health and welfare benefit plan that provides health care and death benefits to certain Xcel Energy retirees. NSP-Wisconsin discontinued contributing toward health care benefits for nonbargaining employees retiring after 1998 and for bargaining employees who retired after 1999. Regulatory agencies for nearly all retail utility customers have allowed rate recovery of accrued postretirement benefit costs. Plan Assets — Certain state agencies that regulate Xcel Energy Inc.’s utility subsidiaries also have issued guidelines related to the funding of postretirement benefit costs. These assets are invested in a manner consistent with the investment strategy for the pension plan. The following table presents the target postretirement asset allocations for Xcel Energy Inc. and NSP-Wisconsin at Dec. 31 for the upcoming year: 2017 2016 Domestic and international equity securities 24 % 25 % Short-to-intermediate fixed income securities 60 57 Alternative investments 9 13 Cash 7 5 Total 100 % 100 % Xcel Energy Inc. and NSP-Wisconsin base investment-return assumptions for the postretirement health care fund assets on expected long-term performance for each of the investment types included in the asset portfolio. Assumptions and target allocations are determined at the master trust level. The investment mix at each of Xcel Energy Inc.’s utility subsidiaries may vary from the investment mix of the total asset portfolio. The assets are invested in a portfolio according to Xcel Energy Inc.’s and NSP-Wisconsin’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 projected 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 particular industry, index, or entity. Market volatility is not considered to be a material factor in postretirement health care costs. The following tables present, for each of the fair value hierarchy levels, NSP-Wisconsin’s proportionate allocation of the total postretirement benefit plan assets that are measured at fair value as of Dec. 31, 2017 and 2016 : Dec. 31, 2017 (Thousands of Dollars) Level 1 Level 2 Level 3 Investments Measured at NAV Total Cash equivalents $ 68 $ — $ — $ — $ 68 Insurance contracts — 115 — — 115 Commingled funds: U.S. equity funds 172 — — — 172 U.S fixed income funds 79 — — — 79 Emerging market debt funds 94 — — — 94 Debt securities: Government securities — 134 — — 134 U.S. corporate bonds — 147 — — 147 Non U.S. corporate bonds — 50 — — 50 Asset-backed securities — 54 — — 54 Mortgage-backed securities — 80 — — 80 Equity securities: Non U.S. equities 82 — — — 82 Other — 3 — — 3 Total $ 495 $ 583 $ — $ — $ 1,078 Dec. 31, 2016 (Thousands of Dollars) Level 1 Level 2 Level 3 Investments Measured at NAV Total Cash equivalents $ 25 $ — $ — $ — $ 25 Insurance contracts — 58 — — 58 Commingled funds: U.S. equity funds 67 — — — 67 U.S fixed income funds 33 — — — 33 Emerging market debt funds 38 — — — 38 Other commingled funds — — — 67 67 Debt securities: Government securities — 46 — — 46 U.S. corporate bonds — 77 — — 77 Non U.S. corporate bonds — 21 — — 21 Asset-backed securities — 23 — — 23 Mortgage-backed securities — 36 — — 36 Equity securities: Non U.S. equities 50 — — — 50 Other — 2 — — 2 Total $ 213 $ 263 $ — $ 67 $ 543 There were no assets transferred in or out of Level 3 for the years ended Dec. 31, 2017 , 2016 and 2015 . Benefit Obligations — A comparison of the actuarially computed benefit obligation and plan assets for NSP-Wisconsin is presented in the following table: (Thousands of Dollars) 2017 2016 Change in Projected Benefit Obligation: Obligation at Jan. 1 $ 14,973 $ 14,718 Service cost 29 24 Interest cost 590 651 Medicare subsidy reimbursements — 7 Plan participants’ contributions 71 87 Actuarial loss 2,069 775 Benefit payments (1,368 ) (1,289 ) Obligation at Dec. 31 $ 16,364 $ 14,973 (Thousands of Dollars) 2017 2016 Change in Fair Value of Plan Assets: Fair value of plan assets at Jan. 1 $ 543 $ 418 Actual loss on plan assets (6 ) (12 ) Plan participants’ contributions 71 87 Employer contributions 1,838 1,339 Benefit payments (1,368 ) (1,289 ) Fair value of plan assets at Dec. 31 $ 1,078 $ 543 (Thousands of Dollars) 2017 2016 Funded Status of Plans at Dec. 31: Funded status $ (15,286 ) $ (14,430 ) Current liabilities (269 ) (822 ) Noncurrent liabilities (15,017 ) (13,608 ) Net postretirement amounts recognized on consolidated balance sheets $ (15,286 ) $ (14,430 ) (Thousands of Dollars) 2017 2016 Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost: Net loss $ 10,553 $ 8,883 Prior service credit (1,783 ) (2,134 ) Total $ 8,770 $ 6,749 (Thousands of Dollars) 2017 2016 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 $ 110 $ — Noncurrent regulatory assets 8,660 6,749 Total $ 8,770 $ 6,749 Measurement date Dec. 31, 2017 Dec. 31, 2016 2017 2016 Significant Assumptions Used to Measure Benefit Obligations: Discount rate for year-end valuation 3.62 % 4.13 % Mortality table RP 2014 RP 2014 Health care costs trend rate — initial Pre-65 7.00 % 5.50 % Health care costs trend rate — initial Post-65 5.50 % 5.50 % Beginning with the Dec. 31, 2017 measurement, Xcel Energy Inc. and NSP-Wisconsin separated its initial medical trend assumption for pre-Medicare (Pre-65) and post-Medicare (Post-65) claims costs of 7.0 percent and 5.5 percent , respectively, in order to reflect different short-term expectations based on recent experience differences. The ultimate trend assumption remained at 4.5 percent for both Pre-65 and Post-65 claims costs as similar long-term trend rates are expected for both populations. The period until the ultimate rate is reached is five years . Xcel Energy Inc. and NSP-Wisconsin base the medical trend assumption on the long-term cost inflation expected in the health care market, considering the levels projected and recommended by industry experts, as well as recent actual medical cost increases experienced by the retiree medical plan. A one-percent change in the assumed health care cost trend rate would have the following effects on NSP-Wisconsin: One-Percentage Point (Thousands of Dollars) Increase Decrease APBO $ 1,588 $ (1,344 ) Service and interest components 65 (55 ) Cash Flows — The postretirement health care plans have no funding requirements under income tax and other retirement-related regulations other than fulfilling benefit payment obligations, when claims are presented and approved under the plans. Additional cash funding requirements are prescribed by certain state and federal rate regulatory authorities. Xcel Energy, which includes NSP-Wisconsin, contributed $20 million , $18 million and $18 million during 2017 , 2016 and 2015 , respectively, of which $2 million , $1 million and $1 million were attributable to NSP-Wisconsin. Xcel Energy expects to contribute approximately $12 million during 2018 , of which $1 million is attributable to NSP-Wisconsin. Plan Amendments — In 2017 and 2016, there were no plan amendments made which affected the benefit obligation. Benefit Costs — The components of NSP-Wisconsin’s net periodic postretirement benefit costs were: (Thousands of Dollars) 2017 2016 2015 Service cost $ 29 $ 24 $ 29 Interest cost 590 651 653 Expected return on plan assets (31 ) (24 ) (30 ) Amortization of prior service credit (351 ) (351 ) (351 ) Amortization of net loss 436 330 456 Net periodic postretirement benefit cost $ 673 $ 630 $ 757 2017 2016 2015 Significant Assumptions Used to Measure Costs: Discount rate 4.13 % 4.65 % 4.08 % Expected average long-term rate of return on assets 5.80 5.80 5.80 In addition to the benefit costs in the table above, for the postretirement health care plans sponsored by Xcel Energy Inc., costs are allocated to NSP-Wisconsin based on Xcel Energy Services Inc. employees’ labor costs. Projected Benefit Payments The following table lists NSP-Wisconsin’s projected benefit payments for the pension and postretirement benefit plans: (Thousands of Dollars) Projected Pension Benefit Payments Gross Projected Postretirement Health Care Benefit Payments Expected Medicare Part D Subsidies Net Projected Postretirement Health Care Benefit Payments 2018 $ 11,189 $ 1,352 $ 5 $ 1,347 2019 11,812 1,329 4 1,325 2020 12,361 1,298 3 1,295 2021 11,842 1,254 3 1,251 2022 11,640 1,215 3 1,212 2023-2027 58,627 5,111 14 5,097 Multiemployer Plans NSP-Wisconsin contributes to several union multiemployer pension plans, none of which are individually significant. These plans provide pension benefits to certain union employees who may perform services for multiple employers and do not participate in the NSP-Wisconsin sponsored pension plans. Contributing to these types of plans creates risk that differs from providing benefits under NSP-Wisconsin 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. Contributions to multiemployer plans were as follows for the years ended Dec. 31, 2017 , 2016 and 2015 . There were no significant changes to the nature or magnitude of the participation of NSP-Wisconsin in multiemployer plans for the years presented: (Thousands of Dollars) 2017 2016 2015 Multiemployer plan contributions: Pension $ 248 $ 707 $ 944

Other Income, Net

Other Income, Net	12 Months Ended
	Dec. 31, 2017
Other Income and Expenses [Abstract]
Other Income, Net	Other Income, Net Other income, net for the years ended Dec. 31 consisted of the following: (Thousands of Dollars) 2017 2016 2015 Interest income $ 716 $ 244 $ 332 Other nonoperating income 325 208 789 Insurance policy (expense) income (195 ) 22 (228 ) Other nonoperating expense (13 ) (13 ) (10 ) Other income, net $ 833 $ 461 $ 883

Fair Value of Financial Assets

Fair Value of Financial Assets and Liabilities	12 Months Ended
	Dec. 31, 2017
Fair Value Disclosures [Abstract]
Fair Value of Financial Assets and Liabilities	Fair Value of Financial Assets and Liabilities Fair Value Measurements The accounting guidance for fair value measurements and disclosures provides a single definition of fair value and requires certain 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. The three levels in the hierarchy are as follows: 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. Specific valuation methods include the following: Cash equivalents — The fair values of cash equivalents are generally based on cost plus accrued interest; money market funds are measured using quoted NAVs. 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. Derivative Instruments Fair Value Measurements NSP-Wisconsin enters into derivative instruments, including forward contracts, futures, swaps and options, for trading purposes and to manage risk in connection with changes in interest rates and utility commodity prices. Interest Rate Derivatives — NSP-Wisconsin enters into various instruments that effectively fix the interest payments on certain floating rate debt obligations or 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. At Dec. 31, 2017, accumulated other comprehensive loss related to interest rate derivatives included $0.1 million of net losses expected to be reclassified into earnings during the next 12 months as the related hedged interest rate transactions impact earnings, including forecasted amounts for unsettled hedges, as applicable. Commodity Derivatives — NSP-Wisconsin may enter 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 natural gas to generate electric energy and natural gas for resale. The following table details the gross notional amounts of commodity options at Dec. 31: (Amounts in Thousands) (a)(b) 2017 2016 MMBtu of natural gas 42 255 (a) Amounts are not reflective of net positions in the underlying commodities. (b) Notional amounts for options are included on a gross basis, but are weighted for the probability of exercise. Consideration of Credit Risk and Concentrations — NSP-Wisconsin continuously monitors the creditworthiness of the 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. Given this assessment, as well as an assessment of the impact of NSP-Wisconsin’s own credit risk when determining the fair value of derivative liabilities, the impact of credit risk was immaterial to the fair value of unsettled commodity derivatives presented in the consolidated balance sheets. NSP-Wisconsin employs additional credit risk control mechanisms when appropriate, such as letters of credit, parental guarantees, standardized master netting agreements and termination provisions that allow for offsetting of positive and negative exposures. Credit exposure is monitored and, when necessary, the activity with a specific counterparty is limited until credit enhancement is provided. Financial Impact of Qualifying Cash Flow Hedges — The impact of qualifying interest rate cash flow hedges on NSP-Wisconsin’s accumulated other comprehensive loss, included in the consolidated statements of common stockholder’s equity and in the consolidated statements of comprehensive income, is detailed in the following table: (Thousands of Dollars) 2017 2016 2015 Accumulated other comprehensive loss related to cash flow hedges at Jan. 1 $ (133 ) $ (209 ) $ (285 ) After-tax net realized losses on derivative transactions reclassified into earnings 76 76 76 Accumulated other comprehensive loss related to cash flow hedges at Dec. 31 $ (57 ) $ (133 ) $ (209 ) Pre-tax losses related to interest rate derivatives reclassified from accumulated other comprehensive loss into earnings were $0.1 million for each of the years ended Dec. 31, 2017, 2016 and 2015. During the years ended Dec. 31, 2017, 2016 and 2015 changes in the fair value of natural gas commodity derivatives resulted in net losses of $0.3 million , $0.2 million and $0.7 million , recognized as regulatory assets and liabilities. The classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms. During the years ended Dec. 31, 2017, 2016 and 2015, $0.2 million , $0.8 million and $1.4 million of natural gas commodity derivatives settlement losses were recognized and were subject to purchased natural gas cost recovery mechanisms, which result in reclassifications of derivative settlement gains and losses out of income to a regulatory asset or liability, as appropriate. NSP-Wisconsin had no derivative instruments designated as fair value hedges during the years ended Dec. 31, 2017, 2016 and 2015. Therefore, no gains or losses from fair value hedges or related hedged transactions were recognized for these periods. Recurring Fair Value Measurements — The following table presents for each of the fair value hierarchy levels, NSP-Wisconsin’s derivative assets and liabilities measured at fair value on a recurring basis: Dec. 31, 2017 Fair Value Fair Value Total Counterparty Netting (a) (Thousands of Dollars) Level 1 Level 2 Level 3 Total (b) Current derivative assets Natural gas commodity $ — $ 14 $ — $ 14 $ — $ 14 Dec. 31, 2016 Fair Value Fair Value Total Counterparty Netting (a) (Thousands of Dollars) Level 1 Level 2 Level 3 Total (b) Current derivative assets Natural gas commodity $ — $ 149 $ — $ 149 $ — $ 149 (a) NSP-Wisconsin nets derivative instruments and related collateral in its consolidated balance sheet 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, 2017 and 2016. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements. (b) Included in the prepayments balance of $3.5 million and $3.1 million at Dec. 31, 2017 and 2016, respectively, in the consolidated balance sheets. Fair Value of Long-Term Debt As of Dec. 31, 2017 and 2016, other financial instruments for which the carrying amount did not equal fair value were as follows: 2017 2016 (Thousands of Dollars) Carrying Amount Fair Value Carrying Amount Fair Value Long-term debt, including current portion $ 761,180 $ 856,106 $ 663,069 $ 730,284 The fair value of NSP-Wisconsin’s long-term debt is estimated based on recent trades and observable spreads from benchmark interest rates for similar securities. The fair value estimates are based on information available to management as of Dec. 31, 2017 and 2016, and given the observability of the inputs to these estimates, the fair values presented for long-term debt have been assigned a Level 2.

Rate Matters (Notes)

Rate Matters (Notes)	12 Months Ended
	Dec. 31, 2017
Public Utilities, General Disclosures [Abstract]
Rate Matters	Rate Matters Tax Reform - Regulatory Proceedings The specific impacts of the TCJA on retail customer rates are subject to regulatory approval. NSP-Wisconsin is in the process of quantifying the rate impacts of the TCJA and addressing these impacts in its open and recently concluded proceedings focused on retail base rate impacts for its utility subsidiaries. In January 2018, the PSCW issued an order requiring public utilities to apply deferred accounting for the impacts of the TCJA. The PSCW has also requested that utilities provide responses to questions on tax reform and its impact on electric and natural gas revenue requirements. In February 2018, NSP-Wisconsin proposed levelizing upcoming rate cases, advancing infrastructure investments and buying down assets such as the regulatory asset for Ashland clean-up. The MPSC has issued an order for utilities to use deferred accounting for the impacts of the TCJA. In February 2018, the MPSC issued an order directing each utility in Michigan to file an application for determination of the benefits related to the reduction in the corporate federal tax rate by March 30, 2018. The MPSC will address the remaining benefits related to the TCJA in the second quarter of 2018. NSP-Wisconsin plans to include the TCJA tax benefits as part of the electric rate case pending before the MPSC. Recently Concluded Regulatory Proceedings — PSCW Wisconsin 2018 Electric and Gas Rate Case — In May 2017, NSP-Wisconsin filed a request with the PSCW to increase electric rates by $25 million , or 3.6 percent , and natural gas rates by $12 million , or 10.1 percent , effective Jan. 1, 2018. The rate filing was based on a 2018 forecast test year, a ROE of 10 percent , an equity ratio of 52.53 percent and a forecasted rate base of approximately $1.2 billion for the electric utility and $138 million for the natural gas utility. In December 2017, the PSCW approved electric and natural gas rate increases of approximately $9 million , or 1.4 percent , and $10 million , or 8.3 percent , respectively, based on a 9.8 percent ROE and an equity ratio of 51.45 percent . New rates went into effect on Jan. 1, 2018. Pending Regulatory Proceedings - MPSC Michigan 2018 Electric Rate Case — In November 2017, NSP-Wisconsin filed a request with the MPSC to increase rates for electric service by $1 million , or 7.1 percent . The filing was based on a 2018 forecast test year, a 10.1 percent ROE, an equity ratio of 52.5 percent and a forecasted average rate base of approximately $43 million . The primary driver of the requested increase is continuing investment in transmission and distribution infrastructure. The filing also included a request for step increases in 2019 and 2020 related to electric distribution system investments in those years. In addition to the MPSC staff, intervenors in the case include the Michigan Attorney General and the Association of Businesses Advocating Tariff Equity, a voluntary association of large industrial businesses. Hearings are scheduled for April 2018. The parties have agreed to meet in March 2018 to discuss potential settlement of the case. Recently Concluded Regulatory Proceedings — MPUC Monticello Prudence Investigation — In 2013, NSP-Minnesota completed the Monticello LCM/EPU project. The multi-year project extended the life of the facility and increased the capacity from 600 to 671 MW in 2015. The Monticello LCM/EPU project expenditures were approximately $665 million . Total capitalized costs were approximately $748 million , which includes AFUDC. In 2008, project expenditures were initially estimated at approximately $320 million , excluding AFUDC. In 2015, the MPUC voted to allow for full recovery, including a return, on $415 million of the total plant costs (inclusive of AFUDC), but only allow recovery of the remaining $333 million of costs with no return on this portion of the investment. As a result, Xcel Energy recorded a pre-tax loss of $129 million in the first quarter of 2015, after which the remaining book value of the Monticello project represented the present value of the estimated future cash flows. As NSP-Wisconsin shares in the costs of the Monticello plant through the Interchange Agreement with NSP-Minnesota, the MPUC decision also affects NSP-Wisconsin. NSP-Wisconsin’s portion of the $129 million pre-tax loss, recorded in the first quarter of 2015, was approximately $5 million . Pending Regulatory Proceedings — FERC MISO ROE Complaints/ROE Adder — In November 2013, a group of customers filed a complaint at the FERC against MISO TOs, including NSP-Minnesota and NSP-Wisconsin. The complaint argued for a reduction in the ROE in transmission formula rates in the MISO region from 12.38 percent to 9.15 percent , and the removal of ROE adders (including those for RTO membership), effective Nov. 12, 2013. In December 2015, an ALJ recommended the FERC approve a base ROE of 10.32 percent for the MISO TOs. The ALJ found the existing 12.38 percent ROE to be unjust and unreasonable. The recommended 10.32 percent ROE applied a FERC ROE policy adopted in a June 2014 order (Opinion 531). The FERC approved the ALJ recommended 10.32 percent base ROE in an order issued in September 2016. This ROE would be applicable for Nov. 12, 2013 to Feb. 11, 2015, and prospectively from the date of the FERC order. The total prospective ROE would be 10.82 percent , including a 50 basis point adder for RTO membership. Various parties requested rehearing of the September 2016 order. The requests are pending FERC action. In February 2015, a second complaint seeking to reduce the MISO ROE from 12.38 percent to 8.67 percent prior to any adder was filed with the FERC, resulting in a second period of potential refund from Feb. 12, 2015 to May 11, 2016. In June 2016, the ALJ recommended a ROE of 9.7 percent , applying the methodology adopted by the FERC in Opinion 531. In April 2017, the D.C. Circuit vacated and remanded Opinion 531. It is unclear how the D.C. Circuit’s opinion to vacate and remand Opinion 531 will affect the September 2016 FERC order or the timing and outcome of the second ROE complaint. In September 2017, certain MISO TOs (not including NSP-Minnesota and NSP-Wisconsin) filed a motion to dismiss the second ROE complaint. The motion to dismiss is pending FERC action. As of Dec. 31, 2017, NSP-Minnesota has processed the refunds for the Nov. 12, 2013 to Feb. 11, 2015 complaint period based on the 10.32 percent ROE. NSP-Minnesota has also recognized a current refund liability consistent with the best estimate of the final ROE for the Feb. 12, 2015 to May 11, 2016 complaint period.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2017
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Commitments and Contingencies Commitments Fuel Contracts — NSP-Wisconsin has entered into various long-term commitments for the purchase and delivery of a significant portion of its current coal and natural gas requirements. These contracts expire in various years between 2018 and 2029 . In addition, NSP-Wisconsin is required to pay additional amounts depending on actual quantities shipped under these agreements. As NSP-Wisconsin does not have an automatic electric fuel adjustment clause for Wisconsin retail customers, NSP-Wisconsin utilizes deferred accounting treatment for future rate recovery or refund when fuel costs differ from the amount included in rates by more than two percent on an annual basis, as determined by the PSCW after an opportunity for a hearing and an earnings test based on NSP-Wisconsin’s authorized ROE. The estimated minimum purchases for NSP-Wisconsin under these contracts as of Dec. 31, 2017 are as follows: (Millions of Dollars) Coal Natural gas Natural gas 2018 $ 6.4 $ 9.4 $ 13.3 2019 0.6 0.4 12.3 2020 0.6 0.3 10.1 2021 0.7 0.3 9.5 2022 0.7 0.2 8.2 Thereafter 0.7 — 30.5 Total (a) $ 9.7 $ 10.6 $ 83.9 (a) Excludes additional amounts allocated to NSP-Wisconsin through intercompany charges. Additional expenditures for fuel and natural gas storage and transportation will be required to meet expected future electric generation and natural gas needs. Leases — NSP-Wisconsin leases a variety of equipment and facilities. These leases, primarily for office space, vehicles, aircraft and power-operated equipment, are accounted for as operating leases. Total expenses under operating lease obligations were approximately $1.2 million , $1.2 million and $1.1 million for 2017 , 2016 and 2015 , respectively. Future commitments under operating leases are: (Millions of Dollars) 2018 $ 0.9 2019 0.9 2020 0.9 2021 0.8 2022 0.8 Thereafter 4.6 Total $ 8.9 Variable Interest Entities — The accounting guidance for consolidation of variable interest entities requires enterprises to consider the activities that most significantly impact an entity’s financial performance, and power to direct those activities, when determining whether an enterprise is a variable interest entity’s primary beneficiary. NSP-Wisconsin has entered into limited partnerships for the construction and operation of affordable rental housing developments which qualify for low-income housing tax credits. NSP-Wisconsin has determined the low-income housing limited partnerships to be variable interest entities primarily due to contractual arrangements within each limited partnership that establish sharing of ongoing voting control and profits and losses that does not consistently align with the partners’ proportional equity ownership. NSP-Wisconsin has determined that it has the power to direct the activities that most significantly impact these entities’ economic performance, and therefore NSP-Wisconsin consolidates these limited partnerships in its consolidated financial statements. Equity financing for these entities has been provided by NSP-Wisconsin and the general partner of each limited partnership, and NSP-Wisconsin’s risk of loss is limited to its capital contributions, adjusted for any distributions and its share of undistributed profits and losses; no significant additional financial support has been, or is required to be provided to the limited partnerships by NSP-Wisconsin. Obligations of the limited partnerships are generally secured by the housing properties of each limited partnership, and the creditors of each limited partnership have no significant recourse to NSP-Wisconsin or its subsidiaries. Likewise, the assets of the limited partnerships may only be used to settle obligations of the limited partnerships, and not those of NSP-Wisconsin or its subsidiaries. Amounts reflected in NSP-Wisconsin’s consolidated balance sheets for low-income housing limited partnerships include the following: (Thousands of Dollars) Dec. 31, 2017 Dec. 31, 2016 Current assets $ 426 $ 375 Property, plant and equipment, net 1,882 2,025 Other noncurrent assets 137 125 Total assets $ 2,445 $ 2,525 Current liabilities $ 1,214 $ 1,269 Mortgages and other long-term debt payable 486 486 Other noncurrent liabilities 56 54 Total liabilities $ 1,756 $ 1,809 Joint Operating System — The electric production and transmission system of NSP-Wisconsin is managed as an integrated system with that of NSP-Minnesota, jointly referred to as the NSP System. The electric production and transmission costs of the entire NSP System are shared by NSP-Minnesota and NSP-Wisconsin. A FERC approved agreement between the two companies, called the Interchange Agreement, provides for the sharing of all costs of generation and transmission facilities of the system, including capital costs. Such costs include current and potential obligations of NSP-Minnesota related to its nuclear generating facilities. NSP-Minnesota’s public liability for claims resulting from any nuclear incident is limited to $13.4 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 in case of a nuclear incident. NSP-Minnesota is subject to assessments of up to $127 million per reactor-incident for each of its three licensed reactors, to be applied for public liability arising from a nuclear incident at any licensed nuclear facility in the United States. The maximum funding requirement is $19 million per reactor per incident during any one year. These maximum assessment amounts are both subject to inflation adjustment by the NRC and state premium taxes. The NRC’s last adjustment was effective September 2013. NSP-Minnesota purchases insurance for property damage and site decontamination cleanup costs from Nuclear Electric Insurance Ltd. (NEIL) and European Mutual Association for Nuclear Insurance (EMANI). The coverage limits are $2.3 billion for each of NSP-Minnesota’s two nuclear plant sites. NEIL also provides business interruption insurance coverage, including the cost of replacement power obtained during certain 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. However, in each calendar year, NSP-Minnesota could be subject to maximum assessments of approximately $19 million for business interruption insurance and $41 million for property damage insurance if losses exceed accumulated reserve funds. Guarantees — NSP-Wisconsin provides a guarantee for payment of customer loans related to NSP-Wisconsin’s farm rewiring program. NSP-Wisconsin’s exposure under the guarantee is based upon the net liability under the agreement. The guarantee issued by NSP-Wisconsin limits the exposure of NSP-Wisconsin to a maximum amount stated in the guarantee. The guarantee contains no recourse provisions and requires no collateral. The following table presents the guarantee issued and outstanding for NSP-Wisconsin: (Millions of Dollars) Guarantee Current Term or Triggering Guarantee of customer loans for the Farm Rewiring Program (a) $ 1.0 $ — 2020 (b) (a) The term of this guarantee expires in 2020 , which is the final scheduled repayment date for the loans. As of Dec. 31, 2017, no claims had been made by the lender. (b) The debtor becomes the subject of bankruptcy or other insolvency proceedings. Environmental Contingencies NSP-Wisconsin has been or is currently involved with the cleanup of contamination from certain hazardous substances at several sites. In many situations, NSP-Wisconsin believes it will recover some portion of these costs through insurance claims. Additionally, where applicable, NSP-Wisconsin is pursuing, or intends to pursue, recovery from other PRPs and through the regulated rate process. New and changing federal and state environmental mandates can also create added financial liabilities for NSP-Wisconsin, which are normally recovered through the regulated rate process. To the extent any costs are not recovered through the options listed above, NSP-Wisconsin would be required to recognize an expense. Site Remediation — Various federal and state environmental laws impose liability, without regard to the legality of the original conduct, where hazardous substances or other regulated materials have been released to the environment. NSP-Wisconsin may sometimes pay all or a portion of the cost to remediate sites where past activities of NSP-Wisconsin or other parties have caused environmental contamination. Environmental contingencies could arise from various situations, including sites of former MGPs operated by NSP-Wisconsin, its predecessors, or other entities; and third-party sites, such as landfills, for which NSP-Wisconsin is alleged to be a PRP that sent wastes to that site. MGP Sites Ashland MGP Site — NSP-Wisconsin was named a PRP for contamination at a site in Ashland, Wis. The Ashland/Northern States Power Lakefront Superfund Site (the Site) includes NSP-Wisconsin property, previously operated as a MGP facility (the Upper Bluff), and two other properties: an adjacent city lakeshore park area (Kreher Park); and an area of Lake Superior’s Chequamegon Bay adjoining the park. In 2012, NSP-Wisconsin agreed to remediate the Phase I Project Area (which includes the Upper Bluff and Kreher Park areas of the Site), under a settlement agreement with the EPA. In January 2017, NSP-Wisconsin agreed to remediate the Phase II Project Area (the Sediments), under a settlement agreement with the EPA. The settlement agreements were approved by the U.S. District Court for the Western District of Wisconsin. NSP-Wisconsin initiated a full scale wet dredge remedy of the Sediments in 2017. Going forward, NSP-Wisconsin anticipates completion of restoration activities of the Sediments in 2018 with finalization of Phase I Project Area construction and restoration activities in 2019. Groundwater treatment activities at the Site will continue. The current cost estimate for the entire site (both Phase I Project Area and the Sediments) is approximately $168 million , of which approximately $138 million has been spent. As of Dec. 31, 2017 and 2016, NSP-Wisconsin had recorded a total liability of $30 million and $64 million , respectively, for the entire site. NSP-Wisconsin has deferred the unrecovered portion of the estimated Site remediation costs as a regulatory asset. The PSCW has authorized NSP-Wisconsin rate recovery for all remediation costs incurred at the Site. In 2012, the PSCW agreed to allow NSP-Wisconsin to pre-collect certain costs, to amortize costs over a ten -year period and to apply a three percent carrying cost to the unamortized regulatory asset. In December 2017, the PSCW approved an NSP-Wisconsin natural gas rate case which included recovery of additional expenses associated with remediating the Site. The annual recovery of MGP clean-up costs will increase from $12 million in 2017 to $18 million in 2018. Other MGP, Landfill or Disposal Sites — In addition to the site in Ashland, Wis., NSP-Wisconsin is currently involved in investigating and/or remediating an MGP, landfill or other disposal site. NSP-Wisconsin has identified one site where contamination is present and where investigation and/or remediation activities are currently underway. Other parties may have responsibility for some portion of the investigation and/or remediation activities that are underway. NSP-Wisconsin anticipates that these investigation or remediation activities will continue through at least 2018. NSP-Wisconsin had accrued $0.1 million for this site at Dec. 31, 2017 and 2016, respectively. NSP-Wisconsin anticipates that any amounts spent will be fully recovered from customers. Environmental Requirements Water and Waste Asbestos Removal — Some of NSP-Wisconsin’s facilities contain asbestos. Most asbestos will remain undisturbed until the facilities that contain it are demolished or removed. NSP-Wisconsin has recorded an estimate for final removal of the asbestos as an ARO. It may be necessary to remove some asbestos to perform maintenance or make improvements to other equipment. The cost of removing asbestos as part of other work is not expected to be material and is recorded as incurred as operating expenses for maintenance projects, capital expenditures for construction projects or removal costs for demolition projects. Federal CWA Waters of the United States Rule — In 2015, the EPA and the U.S. Army Corps of Engineers (Corps) published a final rule that significantly expanded the types of water bodies regulated under the CWA and broadened the scope of waters subject to federal jurisdiction. In October 2015, the U.S. Court of Appeals for the Sixth Circuit issued a nationwide stay of the final rule and subsequently ruled that it, rather than the federal district courts, had jurisdiction over challenges to the rule. In January 2017, the U.S. Supreme Court agreed to resolve the dispute as to which court should hear challenges to the rule. A ruling is expected in 2018. In February 2017, President Trump issued an executive order requiring the EPA and the Corps to review and revise the final rule. On June 27, 2017, the agencies issued a proposed rule that rescinds the final rule and reinstates the prior definition of “Water of the U.S.” The agencies are also undertaking a rulemaking to develop a new definition of “Waters of the U.S.” Federal CWA Effluent Limitations Guidelines (ELG) — In 2015, the EPA issued a final ELG rule for power plants that use coal, natural gas, oil or nuclear materials as fuel and discharge treated effluent to surface waters as well as utility-owned landfills that receive coal combustion residuals. In 2017, the EPA delayed the compliance date for flue gas desulfurization wastewater and bottom ash transport until November 2020 while the agency conducts a rulemaking process to potentially revise the effluent limitations and pretreatment standards for these waste streams. 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 adverse environmental impacts to aquatic species. The EPA published the final 316(b) rule in 2014. The rule prescribes technology for protecting fish that get stuck on plant intake screens (known as impingement) and describes a process for site-specific determinations by each state for sites that must protect the small aquatic organisms that pass through the intake screens into the plant cooling systems (known as entrainment). NSP-Wisconsin believes at least two plants could be required by state regulators to make improvements to reduce entrainment. NSP-Wisconsin estimates the likely cost for complying with impingement requirements may be incurred between 2018 and 2027 and is approximately $4 million , while the total cost of entrainment improvements are anticipated to be immaterial. NSP-Wisconsin anticipates these costs will be fully recoverable in rates. Air GHG Emission Standard for Existing Sources (CPP) — In 2015, the EPA issued its final CPP rule for existing power plants. Among other things, the CPP requires that state plans include enforceable measures to ensure emissions from existing power plants achieve the EPA’s state-specific interim and final emission performance targets. The CPP was challenged by multiple parties in the D.C. Circuit Court. In February 2016, the U.S. Supreme Court issued an order staying the final CPP rule. The stay will remain in effect until the D.C. Circuit Court reaches its decision and the U.S. Supreme Court either declines to review the lower court’s decision or reaches a decision of its own. In March 2017, President Trump signed an executive order requiring the EPA Administrator to review the CPP rule and if appropriate publish proposed rules suspending, revising or rescinding it. Accordingly, the EPA requested that the D.C. Circuit Court hold the litigation in abeyance until the EPA completes its work under the executive order. The D.C. Circuit granted the EPA’s request and is holding the litigation in abeyance, while considering briefs by the parties on whether the court should remand the challenges to the EPA rather than holding them in abeyance, determining whether and how the court continues or ends the stay that currently applies to the CPP. In October 2017, the EPA published a proposed rule to repeal the CPP, based on an analysis that the CPP exceeds the EPA’s statutory authority under the CAA. In the proposal, the EPA stated it has not yet determined whether it will promulgate a new rule to regulate GHG emissions from existing EGUs. In December 2017, the EPA issued an Advanced Notice of Proposed Rulemaking to take and consider comments on whether to issue a future rule and what such a rule should include. Revisions to the NAAQS for Ozone — In 2015, the EPA revised the NAAQS for ozone by lowering the eight -hour standard from 75 parts per billion (ppb) to 70 ppb. In November 2017, the EPA published final designations of areas that meet the 2015 ozone standard. NSP-Wisconsin meets the 2015 ozone standard in all areas where its generating units operate. Asset Retirement Obligations Recorded AROs — AROs have been recorded for property related to the following: electric production (steam, other and hydro), electric distribution and transmission, natural gas distribution, and general property. The electric production obligations include asbestos, processed water and ash-containment facilities, storage tanks and control panels. The asbestos recognition associated with electric production includes certain specific plants. AROs also have been recorded for NSP-Wisconsin steam production related to processed water and ash-containment facilities such as solid waste landfills. NSP-Wisconsin has recognized AROs for the retirement costs of natural gas mains and lines and for the removal of electric transmission and distribution equipment, which consists of obligations associated with polychlorinated biphenyl, lithium batteries, mercury and street lighting lamps. The common general ARO includes obligations related to storage tanks. A reconciliation of NSP-Wisconsin’s AROs for the years ended Dec. 31, 2017 and 2016 is as follows: (Thousands of Dollars) Beginning Balance Liabilities Recognized Accretion Cash Flow Revisions Ending Balance Dec. 31, 2017 (a) Electric plant Steam production asbestos $ 2,194 $ 949 (b) $ 50 $ — $ 3,193 Steam production ash containment 452 — 15 — 467 Electric distribution 32 — 3 — 35 Other 376 — 12 — 388 Natural gas plant Gas distribution 8,293 — 339 1,661 (c) 10,293 Common and other property Common miscellaneous 45 — 2 — 47 Total liability (d) $ 11,392 $ 949 $ 421 $ 1,661 $ 14,423 (a) There were no ARO liabilities settled during the year ended Dec. 31, 2017. (b) The liability recognized relates to asbestos at the French Island plant. (c) Changes in the gas distribution ARO are mainly related to increased labor costs. (d) Included in other long-term liabilities balance in the consolidated balance sheet. (Thousands of Dollars) Beginning Balance Liabilities Settled Accretion Cash Flow Revisions Ending Balance Dec. 31, 2016 (a) Electric plant Steam production asbestos $ 2,145 $ — $ 49 $ — $ 2,194 Steam production ash containment 617 — 18 (183 ) 452 Electric distribution 72 — 3 (43 ) 32 Other 391 (29 ) 14 — 376 Natural gas plant Gas distribution 6,367 — 256 1,670 8,293 Common and other property Common miscellaneous 95 — 2 (52 ) 45 Total liability (b) $ 9,687 $ (29 ) $ 342 $ 1,392 $ 11,392 (a) There were no ARO liabilities recognized during the year ended Dec. 31, 2016. (b) Included in other long-term liabilities balance in the consolidated balance sheet. Indeterminate AROs — Outside of the known and recorded asbestos AROs, other plants or buildings may contain asbestos due to the age of many of NSP-Wisconsin’s facilities, but no confirmation or measurement of the amount of asbestos or cost of removal could be determined as of Dec. 31, 2017. Therefore, an ARO has not been recorded for these facilities. Removal Costs — NSP-Wisconsin records a regulatory liability for the plant removal costs of generation, transmission and distribution facilities that are recovered currently in rates. Generally, the accrual of future non-ARO removal obligations is not required. However, long-standing ratemaking practices approved by applicable state and federal regulatory commissions have allowed provisions for such costs in historical depreciation rates. These removal costs have accumulated over a number of years based on varying rates as authorized by the appropriate regulatory entities. Given the long time periods over which the amounts were accrued and the changing of rates over time, NSP-Wisconsin has estimated the amount of removal costs accumulated through historic depreciation expense based on current factors used in the existing depreciation rates. Accordingly, the recorded amounts of estimated future removal costs are considered regulatory liabilities. Removal costs as of Dec. 31, 2017 and 2016 were $146 million and $140 million , respectively. Legal Contingencies NSP-Wisconsin is involved in various litigation matters that are being defended and handled 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 such losses that are 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 of such matters, including a possible eventual loss. For current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on NSP-Wisconsin’s financial statements. Unless otherwise required by GAAP, legal fees are expensed as incurred. Employment, Tort and Commercial Litigation Gas Trading Litigation — e prime inc. (e prime) is a wholly owned subsidiary of Xcel Energy Inc. e prime was in the business of natural gas trading and marketing but has not engaged in natural gas trading or marketing activities since 2003. Thirteen lawsuits were commenced against e prime and Xcel Energy (and NSP-Wisconsin, in two instances) between 2003 and 2009 alleging fraud and anticompetitive activities in conspiring to restrain the trade of natural gas and manipulate natural gas prices. e prime, Xcel Energy Inc. and its other affiliates were sued along with several other gas marketing companies. These cases were all consolidated in the U.S. District Court in Nevada. Six of the cases remain active, which includes a multi-district litigation (MDL) matter consisting of a Colorado class (Breckenridge), a Wisconsin class (Arandell Corp.), a Missouri class, a Kansas class, and two other cases identified as “Sinclair Oil” and “Farmland.” In March 2017, summary judgment was granted by the MDL judge in favor of Xcel Energy and e prime in the Sinclair Oil and Farmland cases. In November 2017, the U.S District Court in Nevada granted summary judgment against two plaintiffs in the Arandell Corp. case in favor of Xcel Energy and NSP-Wisconsin, leaving only three individual plaintiffs remaining in the litigation. In addition, the plaintiffs’ motions for class certification and remand back to originating courts in these cases were denied in March 2017. Plaintiffs have appealed the summary judgment motions granted in the Farmland and Sinclair Oil cases and the denial of class certification and remand to the U.S. Court of Appeals for the Ninth Circuit (Ninth Circuit). Oral arguments were heard before the Ninth Circuit in February 2018. A final decision is expected by the end of the first quarter of 2019. Xcel Energy, NSP-Wisconsin and e prime have concluded that a loss is remote. Other Contingencies See Note 10 for further discussion.

Regulatory Assets and Liabiliti

Regulatory Assets and Liabilities	12 Months Ended
	Dec. 31, 2017
Regulatory Assets and Liabilities Disclosure [Abstract]
Regulatory Assets and Liabilities	Regulatory Assets and Liabilities NSP-Wisconsin’s consolidated financial statements are prepared in accordance with the applicable accounting guidance, as discussed in Note 1. Under this guidance, 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. Any portion of the business that is not rate regulated cannot establish regulatory assets and liabilities. If changes in the utility industry or the business of NSP-Wisconsin no longer allow for the application of regulatory accounting guidance under GAAP, NSP-Wisconsin would be required to recognize the write-off of regulatory assets and liabilities in net income or OCI. The components of regulatory assets shown on the consolidated balance sheets of NSP-Wisconsin at Dec. 31, 2017 and 2016 are: (Thousands of Dollars) See Note(s) Remaining Dec. 31, 2017 Dec. 31, 2016 Regulatory Assets Current Noncurrent Current Noncurrent Environmental remediation costs 1, 11 Various $ 16,006 $ 136,146 $ 10,669 $ 148,880 Pension and retiree medical obligations (a) 7 Various 5,674 87,505 5,989 93,160 Excess deferred taxes - TCJA 6 Various — 22,605 — — State commission adjustments 1 Plant lives 716 15,932 703 14,008 Recoverable deferred taxes on AFUDC recorded in plant (b) 1 Plant lives — 14,286 — 22,345 Losses on reacquired debt 4 Term of related debt 655 2,678 801 3,333 Other Various 62 3,065 — 4,462 Total regulatory assets $ 23,113 $ 282,217 $ 18,162 $ 286,188 (a) Includes the non-qualified pension plan. (b) Includes a write-down of $11.3 million as a result of the revaluation of deferred tax gross up at the new federal tax rate at Dec. 31, 2017. The components of regulatory liabilities shown on the consolidated balance sheets of NSP-Wisconsin at Dec. 31, 2017 and 2016 are: (Thousands of Dollars) See Note(s) Remaining Dec. 31, 2017 Dec. 31, 2016 Regulatory Liabilities Current Noncurrent Current Noncurrent Excess deferred taxes - TCJA (a) 6 Various $ — $ 236,589 $ — $ — Plant removal costs 11 Plant lives — 146,370 — 139,735 Deferred electric production and natural gas costs 1 Less than one year 13,950 — 11,377 — DOE settlement 11 Less than one year 5,261 — 4,822 — Other Various 1,501 3,848 1,229 8,454 Total regulatory liabilities $ 20,712 $ 386,807 $ 17,428 $ 148,189 (a) Primarily relates to the revaluation of recoverable/regulated plant ADIT and $41.0 million revaluation impact of non-plant ADIT at Dec. 31, 2017.

Other Comprehensive Income

Other Comprehensive Income	12 Months Ended
	Dec. 31, 2017
Stockholders' Equity Note [Abstract]
Other Comprehensive Income	Other Comprehensive Income Changes in accumulated other comprehensive loss, net of tax, for the years ended Dec. 31, 2017 and 2016 were as follows: Gains and Losses on Cash Flow Hedges (Thousands of Dollars) Year Ended Dec. 31, 2017 Year Ended Dec. 31, 2016 Accumulated other comprehensive loss at Jan. 1 $ (133 ) $ (209 ) Losses reclassified from net accumulated other comprehensive loss 76 76 Net current period other comprehensive income 76 76 Adoption of ASU No. 2018-02 (a) (12 ) — Accumulated other comprehensive loss at Dec. 31 $ (69 ) $ (133 ) (a) In 2017, NSP-Wisconsin implemented ASU No. 2018-02 related to the TCJA, which resulted in reclassification of certain credit balances within net accumulated other comprehensive loss to retained earnings. For further information, see Note 2. Reclassifications from accumulated other comprehensive loss for the years ended Dec. 31, 2017 and 2016 were as follows: Amounts Reclassified from Accumulated (Thousands of Dollars) Year Ended Dec. 31, 2017 Year Ended Dec. 31, 2016 Losses on cash flow hedges: Interest rate derivatives $ 126 (a) $ 127 (a) Total, pre-tax 126 127 Tax benefit (50 ) (51 ) Total amounts reclassified, net of tax $ 76 $ 76 (a) Included in interest charges.

Segments and Related Informatio

Segments and Related Information	12 Months Ended
	Dec. 31, 2017
Segment Reporting [Abstract]
Segment Information	Segments and Related Information Operating results from the regulated electric utility and regulated natural gas utility are each separately and regularly reviewed by NSP-Wisconsin’s chief operating decision maker. NSP-Wisconsin 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-Wisconsin has the following reportable segments: regulated electric utility, regulated natural gas utility and all other. • NSP-Wisconsin’s regulated electric utility segment generates electricity which is transmitted and distributed in Wisconsin and Michigan. • NSP-Wisconsin’s regulated natural gas utility segment purchases, transports, stores and distributes natural gas in portions of Wisconsin and Michigan. • Revenues from operating segments not included above are below the necessary quantitative thresholds and are therefore included in the all other category. Those primarily include investments in rental housing projects that qualify for low-income housing tax credits. Asset and capital expenditure information is not provided for NSP-Wisconsin’s reportable segments because as an integrated electric and natural gas utility, NSP-Wisconsin operates significant assets that are not dedicated to a specific business segment, and 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. To report income from operations for regulated electric and regulated natural gas utility segments, the majority of costs are directly assigned to each segment. However, some costs, such as common depreciation, common O&M expenses and interest expense are allocated based on cost causation allocators. A general allocator is used for certain general and administrative expenses, including office supplies, rent, property insurance and general advertising. The accounting policies of the segments are the same as those described in Note 1. (Thousands of Dollars) Regulated Electric Regulated Natural Gas All Other Reconciling Eliminations Consolidated Total 2017 Operating revenues (a) $ 881,891 $ 122,353 $ 1,207 $ — $ 1,005,451 Intersegment revenues 497 287 — (784 ) — Total revenues $ 882,388 $ 122,640 $ 1,207 $ (784 ) $ 1,005,451 Depreciation and amortization $ 88,946 $ 22,070 $ 200 $ — $ 111,216 Interest charges and financing costs 29,396 2,761 23 — 32,180 Income tax expense 38,866 4,040 1,266 — 44,172 Net income 70,876 7,832 708 — 79,416 (Thousands of Dollars) Regulated Electric Regulated Natural Gas All Other Reconciling Eliminations Consolidated Total 2016 Operating revenues (a) $ 849,946 $ 106,157 $ 1,130 $ — $ 957,233 Intersegment revenues 397 487 — (884 ) — Total revenues $ 850,343 $ 106,644 $ 1,130 $ (884 ) $ 957,233 Depreciation and amortization $ 81,299 $ 16,794 $ 201 $ — $ 98,294 Interest charges and financing costs 29,749 2,855 25 — 32,629 Income tax expense (benefit) 40,547 2,445 (90 ) — 42,902 Net income (loss) 65,002 4,503 (370 ) — 69,135 (Thousands of Dollars) Regulated Electric Regulated Natural Gas All Other Reconciling Eliminations Consolidated Total 2015 Operating revenues (a) $ 834,998 $ 120,147 $ 1,396 $ — $ 956,541 Intersegment revenues 419 498 — (917 ) — Total revenues $ 835,417 $ 120,645 $ 1,396 $ (917 ) $ 956,541 Depreciation and amortization $ 77,036 $ 14,034 $ 175 $ — $ 91,245 Interest charges and financing costs 26,494 2,637 90 — 29,221 Income tax expense 40,654 2,501 1,083 — 44,238 Net income 69,398 4,862 376 — 74,636 (a) Operating revenues include $177 million , $170 million and $163 million of intercompany revenue for the years ended Dec. 31, 2017 , 2016 and 2015 respectively. See Note 15 for further discussion of related party transactions by operating segment.

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2017
Related Party Transactions [Abstract]
Related Party Transactions	Related Party Transactions Xcel Energy Services Inc. provides management, administrative and other services for the subsidiaries of Xcel Energy Inc., including NSP-Wisconsin. The services are provided and billed to each subsidiary in accordance with service agreements executed by each subsidiary. NSP-Wisconsin uses 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. 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. The table below contains significant affiliate transactions among the companies and related parties including billings under the Interchange Agreement for the years ended Dec. 31: (Thousands of Dollars) 2017 2016 2015 Operating revenues: Electric $ 177,234 $ 170,483 $ 163,255 Operating expenses: Purchased power 421,609 413,615 419,028 Transmission expense 68,613 61,920 54,070 Natural gas purchased for resale 47 41 45 Other operating expenses — paid to Xcel Energy Services Inc. 92,715 106,454 93,890 Interest expense 7 4 2 Accounts receivable and payable with affiliates at Dec. 31 were: 2017 2016 (Thousands of Dollars) Accounts Accounts Accounts Accounts NSP-Minnesota $ — $ 17,825 $ — $ 18,567 PSCo — 61 — 974 SPS — 7 333 — Other subsidiaries of Xcel Energy Inc. 3,391 11,735 — 9,496 $ 3,391 $ 29,628 $ 333 $ 29,037

Summarized Quarterly Financial

Summarized Quarterly Financial Data (Unaudited)	12 Months Ended
	Dec. 31, 2017
Quarterly Financial Information Disclosure [Abstract]
Summarized Quarterly Financial Data (Unaudited)	Summarized Quarterly Financial Data (Unaudited) Quarter Ended (Thousands of Dollars) March 31, 2017 June 30, 2017 Sept. 30, 2017 Dec. 31, 2017 Operating revenues $ 264,931 $ 230,026 $ 247,511 $ 262,983 Operating income 42,775 29,067 38,392 37,994 Net income 22,419 14,241 22,325 20,431 Quarter Ended (Thousands of Dollars) March 31, 2016 June 30, 2016 Sept. 30, 2016 Dec. 31, 2016 Operating revenues $ 254,850 $ 219,173 $ 246,144 $ 237,066 Operating income 35,448 27,778 46,342 30,360 Net income 17,631 12,625 24,221 14,658

Schedule II, Valuation and Qual

Schedule II, Valuation and Qualifying Accounts	12 Months Ended
	Dec. 31, 2017
Valuation and Qualifying Accounts [Abstract]
Schedule II, Valuation and Qualifying Accounts	NSP-WISCONSIN AND SUBSIDIARIES VALUATION AND QUALIFYING ACCOUNTS YEARS ENDED DEC. 31, 2017 , 2016 AND 2015 (amounts in thousands) Additions Balance at Jan. 1 Charged to Costs and Expenses Charged to Other Accounts (a) Deductions from Reserves (b) Balance at Dec. 31 Allowance for bad debts: 2017 $ 4,865 $ 4,105 $ 952 $ 5,049 $ 4,873 2016 5,128 3,730 1,008 5,001 4,865 2015 5,821 3,947 1,161 5,801 5,128 (a) Recovery of amounts previously written off. (b) Deductions relate primarily to bad debt write-offs.

Summary of Significant Accoun29

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2017
Accounting Policies [Abstract]
Business and System of Accounts	Business and System of Accounts — NSP-Wisconsin is engaged in the regulated generation, transmission, distribution and sale of electricity and in the regulated purchase, transportation, distribution and sale of natural gas. NSP-Wisconsin’s consolidated financial statements and disclosures are presented in accordance with GAAP. All of NSP-Wisconsin’s underlying accounting records also conform to the FERC uniform system of accounts or to systems required by various state regulatory commissions, which are the same in all material respects.
Principles of Consolidation	Principles of Consolidation — NSP-Wisconsin’s consolidated financial statements include its wholly-owned subsidiaries and variable interest entities for which it is the primary beneficiary. In the consolidation process, all intercompany transactions and balances are eliminated. NSP-Wisconsin has investments in certain transmission facilities jointly owned with nonaffiliated utilities. NSP-Wisconsin’s proportionate share of jointly owned facilities is recorded as property, plant and equipment on the consolidated balance sheets and NSP-Wisconsin’s proportionate share of the operating costs associated with these facilities is included in its consolidated statements of income. See Note 5 for further discussion of jointly owned transmission facilities and related ownership percentages. NSP-Wisconsin evaluates its arrangements and contracts with other entities to determine if the other party is a variable interest entity, if NSP-Wisconsin has a variable interest and if NSP-Wisconsin is the primary beneficiary. NSP-Wisconsin follows accounting guidance for variable interest entities which requires consideration of the activities that most significantly impact an entity’s financial performance and power to direct those activities, when determining whether NSP-Wisconsin is a variable interest entity’s primary beneficiary. See Note 11 for further discussion of variable interest entities.
Use of Estimates	Use of Estimates — In recording transactions and balances resulting from business operations, NSP-Wisconsin uses estimates based on the best information available. Estimates are used for such items 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. The recorded estimates are revised when better information becomes available or when actual amounts can be determined. Those revisions can affect operating results.
Regulatory Accounting	Regulatory Accounting — NSP-Wisconsin accounts for certain 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 OCI, are deferred as regulatory assets based on the expected ability to recover the costs in future rates; and • Certain credits, which would otherwise be reflected as income or OCI, 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 restructuring or other changes in the regulatory environment occur, NSP-Wisconsin may no longer be eligible to apply this accounting treatment, and may be required to eliminate regulatory assets and liabilities from its balance sheets. Such changes could have a material effect on NSP-Wisconsin’s financial condition, results of operations and cash flows. See Note 12 for further discussion of regulatory assets and liabilities.
Revenue Recognition	Revenue Recognition — Revenues related to the sale of energy are generally recorded when service is rendered or energy is delivered to customers. However, the determination of the energy sales to individual customers is based on the reading of their meter, which occurs on a systematic basis 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-Wisconsin presents its revenues net of any excise or other fiduciary-type taxes or fees. NSP-Wisconsin has various rate-adjustment mechanisms in place that provide for the recovery of purchased natural gas, electric fuel and purchased energy costs. These 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, under governing regulatory commission rate orders, 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. Under Wisconsin rules, NSP-Wisconsin must submit a forward looking fuel cost plan annually for approval by the PSCW. The rules also allow for deferral of any under-recovery or over-recovery of fuel costs in excess of a two percent annual tolerance band, for future rate recovery or refund, subject to PSCW approval.
Conservation Programs	Conservation Programs — NSP-Wisconsin participates in and funds conservation programs in its retail jurisdictions to assist customers in conserving energy and reducing peak demand on the electric and natural gas systems. NSP-Wisconsin recovers approved conservation program costs in base rate revenue. For operations in the state of Wisconsin, NSP-Wisconsin is required to contribute 1.2 percent of its three -year average annual operating revenues to the statewide energy efficiency and renewable resource program Focus on Energy. Funding is collected through base rates, and there is no financial incentive provided to the utility. The PSCW has full oversight of Focus on Energy including auditing and verification of programs. The program portfolio is outsourced to a third-party administrator who subcontracts as necessary to implement programs.
Property, Plant and Equipment and Depreciation	Property, Plant and Equipment and Depreciation — 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 major 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 also includes costs associated with property held for future use. The depreciable lives of certain plant assets are reviewed annually and revised, if appropriate. 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-Wisconsin records depreciation expense related to its plant using the straight-line method over the plant’s 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. Depreciation expense, expressed as a percentage of average depreciable property, was approximately 3.4 , 3.3 and 3.4 percent for the years ended Dec. 31, 2017, 2016 and 2015, respectively.
Leases	Leases — NSP-Wisconsin evaluates a variety of contracts for lease classification at inception, including rental arrangements for office space, vehicles and equipment. Contracts determined to contain a lease because of per unit pricing that is other than fixed or market price, terms regarding the use of a particular asset, and other factors are evaluated further to determine if the arrangement is a capital lease. See Note 11 for further discussion of leases.
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 nonoperating income (for equity capital) and interest charges (for debt capital). AFUDC amounts capitalized are included in NSP-Wisconsin’s rate base for establishing utility service rates. Generally, AFUDC costs are recovered from customers as the related property is depreciated. However, in some cases, the PSCW has allowed an AFUDC calculation greater than the FERC-defined AFUDC rate, resulting in higher recognition of AFUDC. In some cases for certain transmission projects, the FERC has approved a more current recovery of the cost of capital associated with large capital projects, resulting in a lower recognition of AFUDC.
Asset Retirement Obligations	AROs — NSP-Wisconsin 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. NSP-Wisconsin also recovers through rates certain future plant removal costs in addition to AROs. The accumulated removal costs for these obligations are reflected in the balance sheets as a regulatory liability. See Note 11 for further discussion of AROs.
Income Taxes	Income Taxes — NSP-Wisconsin accounts for income taxes using the asset and liability method, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the financial statements. NSP-Wisconsin 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-Wisconsin uses the tax 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-Wisconsin’s tax rate changes are generally subject to a normalization method of accounting. Therefore, the revaluation of most its net deferred taxes upon a tax rate reduction results in the establishment of a net regulatory liability which will be refundable to utility customers over the remaining life of the related assets. A tax rate increase would result in the establishment of a similar regulatory asset. 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, the reversal of some temporary differences are accounted for as current income tax expense. 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 certain regulatory assets and liabilities related to income taxes, which are summarized in Note 12. 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. In making such a determination, all available evidence is considered, including scheduled reversals of deferred tax liabilities, projected future taxable income, tax planning strategies and recent financial operations. NSP-Wisconsin 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-Wisconsin 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. NSP-Wisconsin reports interest and penalties related to income taxes within the other income and interest charges sections in the consolidated statements of income. Xcel Energy Inc. and its subsidiaries, including NSP-Wisconsin, file consolidated federal income tax returns as well as combined or separate state income tax returns. Federal income taxes paid by Xcel Energy Inc. are allocated to Xcel Energy Inc.’s subsidiaries based on separate company computations of tax. A similar allocation is made for state income taxes paid by Xcel Energy Inc. in connection with combined state filings. Xcel Energy Inc. also allocates its own income tax benefits to its direct subsidiaries which are recorded directly in equity by the subsidiaries based on the relative positive tax liabilities of the subsidiaries. See Note 6 for further discussion of income taxes.
Types of and Accounting for Derivative Instruments	Types of and Accounting for Derivative Instruments — NSP-Wisconsin uses derivative instruments in connection with its utility commodity price and interest rate activities, including forward contracts, futures, swaps and options. All derivative instruments not designated and qualifying for the normal purchases and normal sales exception, as defined by the accounting guidance for derivatives and hedging, are recorded on the consolidated balance sheets at fair value as derivative instruments. This includes certain instruments used to mitigate market risk for the utility operations. The 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. The classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms. Interest rate hedging transactions are recorded as a component of interest expense. NSP-Wisconsin is allowed to recover in electric or natural gas rates the costs of certain financial instruments purchased to reduce commodity cost volatility. For further information on derivatives entered to mitigate commodity price risk on behalf of electric and natural gas customers, see Note 9. Cash Flow Hedges — Certain qualifying hedging relationships are designated as a hedge of a forecasted transaction or future cash flow (cash flow hedge). Changes in the fair value of a derivative designated as a cash flow hedge, to the extent effective, are included in OCI, or deferred as a regulatory asset or liability based on recovery mechanisms until earnings are affected by the hedged transaction. Normal Purchases and Normal Sales — NSP-Wisconsin enters into contracts for the purchase and sale of commodities for use in its business operations. Derivatives and hedging accounting guidance requires a company to evaluate these contracts to determine whether the contracts are derivatives. Certain contracts that meet the definition of a derivative may be exempted from derivative accounting if designated as normal purchases or normal sales. NSP-Wisconsin evaluates all of its contracts at inception to determine if they are derivatives and if they meet the normal purchases and normal sales designation requirements. See Note 9 for further discussion of NSP-Wisconsin’s risk management and derivative activities.
Fair Value Measurements	Fair Value Measurements — NSP-Wisconsin presents cash equivalents, interest rate derivatives and commodity derivatives 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 as a primary input 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 for an identical contract in an active market, NSP-Wisconsin may use quoted prices for similar contracts, or internally prepared valuation models to determine fair value. For the pension and postretirement plan assets published trading data and pricing models, generally using the most observable inputs available, are utilized to estimate fair value for each security. See Notes 7 and 9 for further discussion.
Cash and Cash Equivalents	Cash and Cash Equivalents — NSP-Wisconsin considers investments in certain instruments, including commercial paper and money market funds, 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-Wisconsin establishes an allowance for uncollectible receivables based on a policy that reflects its expected exposure to the credit risk of customers.
Inventory	Inventory — All inventory is recorded at average cost.
Renewable Energy Credits	RECs — RECs are marketable environmental instruments that represent proof that energy was generated from eligible renewable energy sources. RECs are awarded upon delivery of the associated energy and can be bought and sold. RECs are typically used as a form of measurement of compliance to RPS enacted by those states that are encouraging construction and consumption from renewable energy sources, but can also be sold separately from the energy produced. NSP-Wisconsin acquires RECs from the generation or purchase of renewable power. When RECs are purchased or acquired in the course of generation they are recorded as inventory at cost. The cost of RECs that are utilized for compliance purposes is recorded as electric fuel and purchased power expense. Sales of RECs that are purchased or acquired in the course of generation are recorded in electric utility operating revenues on a gross basis. The cost of these RECs and related transaction costs are recorded in electric fuel and purchased power expense.
Emission Allowances	Emission Allowances — Emission allowances, including the annual SO 2 and NOx emission allowance entitlement received from the EPA, are recorded at cost plus associated broker commission fees. NSP-Wisconsin follows the inventory accounting model for all emission allowances. Sales of emission allowances are included in electric utility operating revenues and the operating activities section of the consolidated statements of cash flows.
Environmental Costs	Environmental Costs — Environmental costs are recorded when it is probable NSP-Wisconsin 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. If an environmental expense is related to facilities currently in use, such as emission-control equipment, the cost is capitalized and depreciated over the life of the plant. Estimated remediation costs, excluding inflationary increases, are recorded based on experience, an assessment of the current situation and the technology currently available for use in the remediation. The recorded costs are regularly adjusted as estimates are revised and remediation proceeds. If other participating PRPs exist and acknowledge their potential involvement with a site, costs are estimated and recorded only for NSP-Wisconsin’s expected share of the cost. Any future costs of restoring sites where operation may be extended are treated as a capitalized cost of plant retirement. The depreciation expense levels recoverable in rates include a provision for removal expenses, which may include final remediation costs. Removal costs recovered in rates before the related costs are incurred are classified as a regulatory liability. See Note 11 for further discussion of environmental costs.
Benefit Plans and Other Postretirement Benefits	Benefit Plans and Other Postretirement Benefits — NSP-Wisconsin maintains pension and postretirement benefit plans for eligible employees. Recognizing the cost of providing benefits and measuring the projected benefit obligation of these plans under applicable accounting guidance requires management to make various assumptions and estimates. Based on regulatory recovery mechanisms, certain unrecognized actuarial gains and losses and unrecognized prior service costs or credits are recorded as regulatory assets and liabilities, rather than OCI. See Note 7 for further discussion of benefit plans and other postretirement benefits.
Guarantees	Guarantees — NSP-Wisconsin recognizes, upon issuance or modification of a guarantee, a liability for the fair market value of the obligation that has been assumed in issuing the guarantee. This liability includes consideration of specific triggering events and other conditions which may modify the ongoing obligation to perform under the guarantee. The obligation recognized is reduced over the term of the guarantee as NSP-Wisconsin is released from risk under the guarantee. See Note 11 for specific details of issued guarantees.
Subsequent Events	Subsequent Events — Management has evaluated the impact of events occurring after Dec. 31, 2017 up to the date of issuance of these consolidated financial statements. These statements contain all necessary adjustments and disclosures resulting from that evaluation.

Selected Balance Sheet Data (Ta

Selected Balance Sheet Data (Tables)	12 Months Ended
	Dec. 31, 2017
Balance Sheet Related Disclosures [Abstract]
Accounts Receivable, Net	(Thousands of Dollars) Dec. 31, 2017 Dec. 31, 2016 Accounts receivable, net (a) Accounts receivable $ 68,073 $ 58,896 Less allowance for bad debts (4,873 ) (4,865 ) $ 63,200 $ 54,031
Inventories	(Thousands of Dollars) Dec. 31, 2017 Dec. 31, 2016 Inventories Materials and supplies $ 6,916 $ 6,582 Fuel 3,866 4,743 Natural gas 6,976 6,984 $ 17,758 $ 18,309
Property, Plant and Equipment, Net	(Thousands of Dollars) Dec. 31, 2017 Dec. 31, 2016 Property, plant and equipment, net Electric plant $ 2,602,671 $ 2,499,401 Natural gas plant 326,723 294,986 Common and other property 181,105 156,316 CWIP 148,770 118,822 Total property, plant and equipment 3,259,269 3,069,525 Less accumulated depreciation (1,170,541 ) (1,121,888 ) $ 2,088,728 $ 1,947,637

Borrowings and Other Financin31

Borrowings and Other Financing Instruments (Tables)	12 Months Ended
	Dec. 31, 2017
Borrowings and Other Financing Instruments [Abstract]
Credit Facilities	At Dec. 31, 2017 , NSP-Wisconsin had the following committed credit facility available (in millions): Credit Facility (a) Drawn (b) Available $ 150 $ 11 $ 139 (a) This credit facility matures in June 2021 . (b) Includes outstanding commercial paper.
Commercial Paper
Borrowings and Other Financing Instruments [Abstract]
Short-term Borrowings	Commercial paper outstanding for NSP-Wisconsin was as follows: (Amounts in Millions, Except Interest Rates) Three Months Ended Dec. 31, 2017 Borrowing limit $ 150 Amount outstanding at period end 11 Average amount outstanding 70 Maximum amount outstanding 129 Weighted average interest rate, computed on a daily basis 1.38 % Weighted average interest rate at period end 1.73 (Amounts in Millions, Except Interest Rates) Twelve Months Ended Dec. 31, 2017 Twelve Months Ended Dec. 31, 2016 Twelve Months Ended Dec. 31, 2015 Borrowing limit $ 150 $ 150 $ 150 Amount outstanding at period end 11 60 10 Average amount outstanding 52 15 39 Maximum amount outstanding 129 64 122 Weighted average interest rate, computed on a daily basis 1.23 % 0.69 % 0.44 % Weighted average interest rate at period end 1.73 0.95 0.70
Notes Payable, Other Payables
Borrowings and Other Financing Instruments [Abstract]
Short-term Borrowings	The following table presents the notes payable of Clearwater Investments, Inc., a NSP-Wisconsin subsidiary, to Xcel Energy Inc.: (Amounts in Millions, Except Interest Rates) Dec. 31, 2017 Dec. 31, 2016 Notes payable to affiliates $ 0.5 $ 0.5 Weighted average interest rate 1.73 % 0.95 %

Joint Ownership of Transmissi32

Joint Ownership of Transmission Facilities (Tables)	12 Months Ended
	Dec. 31, 2017
Joint Ownership of Transmission Facilities [Abstract]
Investments in Jointly Owned Transmission Facilities	Following are the investments by NSP-Wisconsin in jointly owned transmission facilities and the related ownership percentages as of Dec. 31, 2017 : (Thousands of Dollars) Plant in Accumulated Depreciation CWIP Ownership % Electric Transmission: CapX2020 Transmission $ 162,108 $ 12,205 $ 103,144 81 % La Crosse, Wis. to Madison, Wis. — — 101,546 37 Total $ 162,108 $ 12,205 $ 204,690

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2017
Income Tax Examination [Line Items]
Summary of Statute of Limitations Applicable to Open Tax Years [Table Text Block]	NSP-Wisconsin is a member of the Xcel Energy affiliated group that files a consolidated federal income tax return. The statutes of limitations applicable to Xcel Energy’s federal income tax returns expire as follows: Tax Year(s) Expiration 2009 - 2011 June 2018 2012 - 2013 October 2018 2014 September 2018 2015 September 2019 2016 September 2020
Reconciliation of Unrecognized Tax Benefits	A reconciliation of the amount of unrecognized tax benefit is as follows: (Millions of Dollars) Dec. 31, 2017 Dec. 31, 2016 Unrecognized tax benefit — Permanent tax positions $ 1.4 $ 0.4 Unrecognized tax benefit — Temporary tax positions 1.0 4.9 Total unrecognized tax benefit $ 2.4 $ 5.3 A reconciliation of the beginning and ending amount of unrecognized tax benefit is as follows: (Millions of Dollars) 2017 2016 2015 Balance at Jan. 1 $ 5.3 $ 4.5 $ 3.0 Additions based on tax positions related to the current year 0.4 0.5 1.9 Reductions based on tax positions related to the current year (0.3 ) — (0.3 ) Additions for tax positions of prior years 1.3 0.5 0.8 Reductions for tax positions of prior years (4.3 ) (0.2 ) (0.9 ) Balance at Dec. 31 $ 2.4 $ 5.3 $ 4.5
Tax Benefits Associated with NOL and Tax Credit Carryforwards	The unrecognized tax benefit amounts were reduced by the tax benefits associated with NOL and tax credit carryforwards. The amounts of tax benefits associated with NOL and tax credit carryforwards are as follows: (Millions of Dollars) Dec. 31, 2017 Dec. 31, 2016 NOL and tax credit carryforwards $ (1.9 ) $ (1.2 )
NOL and Tax Credit Carryforwards	Other Income Tax Matters — NOL amounts represent the amount of 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) 2017 2016 Federal NOL carryforward $ 58 $ 97 Federal tax credit carryforwards 4 4 State NOL carryforward 5 3
Schedule of Effective Income Tax Rate Reconciliation	Total income tax expense from operations differs from the amount computed by applying the statutory federal income tax rate to income before income tax expense. The following reconciles such differences for the years ending Dec. 31: 2017 2016 (b) 2015 (b) Federal statutory rate 35.0 % 35.0 % 35.0 % State income tax on pretax income, net of federal tax effect 5.1 % 5.1 % 5.1 % Increases (decreases) in tax from: Adjustments attributable to tax returns (2.3 ) (0.3 ) (0.4 ) Regulatory differences - effects of rate changes (a) (0.1 ) (0.2 ) (0.2 ) Regulatory differences - other utility plant items (1.7 ) (0.6 ) (1.8 ) Tax credits recognized, net of federal income tax expense (1.0 ) (0.7 ) (0.7 ) Change in unrecognized tax benefits 0.8 0.1 0.1 Other, net (0.1 ) (0.1 ) 0.1 Effective income tax rate 35.7 % 38.3 % 37.2 % (a) The amortization of excess deferred taxes. (b) The prior periods included in this footnote have been reclassified to conform to current year presentation.
Schedule of Components of Income Tax Expense (Benefit)	The components of income tax expense for the years ending Dec. 31 were: (Thousands of Dollars) 2017 2016 2015 Current federal tax expense (benefit) $ 2,765 $ 5,367 $ (4,715 ) Current state tax (benefit) expense (1 ) 131 2,150 Current change in unrecognized tax (benefit) expense (3,626 ) 559 1,498 Deferred federal tax expense 32,919 29,588 40,580 Deferred state tax expense 7,972 8,212 6,675 Deferred change in unrecognized tax expense (benefit) 4,666 (432 ) (1,422 ) Deferred investment tax credits (523 ) (523 ) (528 ) Total income tax expense $ 44,172 $ 42,902 $ 44,238 The components of deferred income tax expense for the years ending Dec. 31 were: (Thousands of Dollars) 2017 2016 2015 Deferred tax (benefit) expense excluding items below $ (173,906 ) $ 39,530 $ 51,084 Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities 219,514 (2,112 ) (5,200 ) Tax expense allocated to other comprehensive income, net of adoption of ASU No. 2018-02, and other (51 ) (50 ) (51 ) Deferred tax expense $ 45,557 $ 37,368 $ 45,833
Schedule of Deferred Tax Assets and Liabilities	The components of the net deferred tax liability at Dec. 31 were as follows: (Thousands of Dollars) 2017 2016 (a) Deferred tax liabilities: Difference between book and tax bases of property $ 270,425 $ 412,071 Regulatory assets 58,436 63,825 Pension expense 14,245 21,575 Other 6,855 9,666 Total deferred tax liabilities $ 349,961 $ 507,137 Deferred tax assets: Regulatory liabilities $ 55,768 $ (5,788 ) NOL carryforward 12,606 35,216 Environmental remediation 8,068 25,842 Tax credit carryforward 4,644 3,704 Other employee benefits 3,868 6,132 Deferred investment tax credits 3,175 4,996 Other 5,145 6,442 Total deferred tax assets $ 93,274 $ 76,544 Net deferred tax liability $ 256,687 $ 430,593 (a) The prior period included in this footnote has been reclassified to conform to current year presentation.

Benefit Plans and Other Postr34

Benefit Plans and Other Postretirement Benefits (Tables)	12 Months Ended
	Dec. 31, 2017
Benefit Plans and Other Postretirement Benefits [Abstract]
Change in Projected Benefit Obligation	A comparison of the actuarially computed pension benefit obligation and plan assets for NSP-Wisconsin is presented in the following table: (Thousands of Dollars) 2017 2016 Accumulated Benefit Obligation at Dec. 31 $ 145,387 $ 146,448 Change in Projected Benefit Obligation: Obligation at Jan. 1 $ 157,457 $ 152,545 Service cost 4,618 4,417 Interest cost 6,218 6,816 Plan amendments (713 ) 305 Actuarial loss 6,499 7,315 Benefit payments (a) (17,331 ) (13,941 ) Obligation at Dec. 31 $ 156,748 $ 157,457
Projected Benefit Payments for the Pension and Postretirement Benefit Plans	The following table lists NSP-Wisconsin’s projected benefit payments for the pension and postretirement benefit plans: (Thousands of Dollars) Projected Pension Benefit Payments Gross Projected Postretirement Health Care Benefit Payments Expected Medicare Part D Subsidies Net Projected Postretirement Health Care Benefit Payments 2018 $ 11,189 $ 1,352 $ 5 $ 1,347 2019 11,812 1,329 4 1,325 2020 12,361 1,298 3 1,295 2021 11,842 1,254 3 1,251 2022 11,640 1,215 3 1,212 2023-2027 58,627 5,111 14 5,097
Contributions to Multiemployer Plans	Contributions to multiemployer plans were as follows for the years ended Dec. 31, 2017 , 2016 and 2015 . There were no significant changes to the nature or magnitude of the participation of NSP-Wisconsin in multiemployer plans for the years presented: (Thousands of Dollars) 2017 2016 2015 Multiemployer plan contributions: Pension $ 248 $ 707 $ 944
Pension Plan [Member]
Benefit Plans and Other Postretirement Benefits [Abstract]
Target Asset Allocations and Plan Assets Measured at Fair Value	The following tables present, for each of the fair value hierarchy levels, NSP-Wisconsin’s pension plan assets that are measured at fair value as of Dec. 31, 2017 and 2016 : Dec. 31, 2017 (Thousands of Dollars) Level 1 Level 2 Level 3 Investments Measured at NAV Total Cash equivalents $ 8,091 $ — $ — $ — $ 8,091 Commingled funds: U.S. equity funds 21,850 — — — 21,850 Non U.S. equity funds 3,900 — — 8,479 12,379 U.S. corporate bond funds 14,035 — — — 14,035 Emerging market equity funds — — — 13,381 13,381 Emerging market debt funds 3,198 — — 7,079 10,277 Private equity investments — — — 3,583 3,583 Real estate — — — 8,309 8,309 Other commingled funds 206 — — 4,965 5,171 Debt securities: Government securities — 12,167 — — 12,167 U.S. corporate bonds — 10,178 — — 10,178 Non U.S. corporate bonds — 1,730 — — 1,730 Equity securities: U.S. equities 4,863 — — — 4,863 Other (1,334 ) 149 — 23 (1,162 ) Total $ 54,809 $ 24,224 $ — $ 45,819 $ 124,852 Dec. 31, 2016 (Thousands of Dollars) Level 1 Level 2 Level 3 Investments Measured at NAV Total Cash equivalents $ 3,939 $ — $ — $ — $ 3,939 Commingled funds: U.S. equity funds 21,415 — — — 21,415 Non U.S. equity funds 7,406 — — 8,942 16,348 U.S. corporate bond funds 10,581 — — — 10,581 Emerging market equity funds — — — 8,577 8,577 Emerging market debt funds 3,519 — — 3,787 7,306 Commodity funds — — — 889 889 Private equity investments — — — 4,652 4,652 Real estate — — — 8,108 8,108 Other commingled funds — — — 8,752 8,752 Debt securities: Government securities — 12,773 — — 12,773 U.S. corporate bonds — 9,432 — — 9,432 Non U.S. corporate bonds — 1,514 — — 1,514 Mortgage-backed securities — 254 — — 254 Asset-backed securities — 120 — — 120 Equity securities: U.S. equities 4,219 — — — 4,219 Other — 97 — — 97 Total $ 51,079 $ 24,190 $ — $ 43,707 $ 118,976 The following table presents the target pension asset allocations for NSP-Wisconsin at Dec. 31 for the upcoming year: 2017 2016 Domestic and international equity securities 38 % 40 % Long-duration fixed income and interest rate swap securities 23 23 Short-to-intermediate fixed income securities 21 16 Alternative investments 16 19 Cash 2 2 Total 100 % 100 %
Change in Fair Value of Plan Assets	(Thousands of Dollars) 2017 2016 Change in Fair Value of Plan Assets: Fair value of plan assets at Jan. 1 $ 118,976 $ 119,314 Actual return on plan assets 13,923 6,163 Employer contributions 9,284 7,440 Benefit payments (a) (17,331 ) (13,941 ) Fair value of plan assets at Dec. 31 $ 124,852 $ 118,976
Funded Status of Plans	(Thousands of Dollars) 2017 2016 Funded Status of Plans at Dec. 31: Funded status (b) $ (31,896 ) $ (38,481 ) (a) 2017 amount includes approximately $13 million of lump-sum benefit payments used in the determination of a settlement charge. (b) Amounts are recognized in noncurrent liabilities on NSP-Wisconsin’s consolidated balance sheets.
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost	(Thousands of Dollars) 2017 2016 Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost: Net loss $ 80,429 $ 91,531 Prior service (credit) cost (346 ) 750 Total $ 80,083 $ 92,281
Amounts Not Yet Recognized as Components of Net Periodic Benefit Costs Recorded on the Balance Sheet Based Upon Expected Recovery in Rates	(Thousands of Dollars) 2017 2016 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 $ 5,548 $ 5,972 Noncurrent regulatory assets 74,535 86,309 Total $ 80,083 $ 92,281
Schedule of Assumptions Used	Measurement date Dec. 31, 2017 Dec. 31, 2016 2017 2016 Significant Assumptions Used to Measure Benefit Obligations: Discount rate for year-end valuation 3.63 % 4.13 % Expected average long-term increase in compensation level 3.75 3.75 Mortality table RP 2014 RP 2014 2017 2016 2015 Significant Assumptions Used to Measure Costs: Discount rate 4.13 % 4.66 % 4.11 % Expected average long-term increase in compensation level 3.75 4.00 3.75 Expected average long-term rate of return on assets 7.10 7.10 7.25
Components of Net Periodic Benefit Costs	The components of NSP-Wisconsin’s net periodic pension cost were: (Thousands of Dollars) 2017 2016 2015 Service cost $ 4,618 $ 4,417 $ 4,759 Interest cost 6,218 6,816 6,520 Expected return on plan assets (9,180 ) (9,157 ) (9,483 ) Amortization of prior service cost 138 111 111 Amortization of net loss 5,846 5,392 6,804 Settlement charge (a) 7,107 — — Net periodic pension cost 14,747 7,579 8,711 Costs not recognized due to effects of regulation (4,176 ) — — Net benefit cost recognized for financial reporting $ 10,571 $ 7,579 $ 8,711 (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 the fourth quarter of 2017 as a result of lump-sum distributions during the 2017 plan year, NSP-Wisconsin recorded a total pension settlement charge of $7 million , the majority of which was not recognized due to the effects of regulation. A total of $2 million of that amount was recorded in O&M expenses in the fourth quarter of 2017. 2017 2016 2015 Significant Assumptions Used to Measure Costs: Discount rate 4.13 % 4.66 % 4.11 % Expected average long-term increase in compensation level 3.75 4.00 3.75 Expected average long-term rate of return on assets 7.10 7.10 7.25
Other Postretirement Benefits Plan [Member]
Benefit Plans and Other Postretirement Benefits [Abstract]
Target Asset Allocations and Plan Assets Measured at Fair Value	The following table presents the target postretirement asset allocations for Xcel Energy Inc. and NSP-Wisconsin at Dec. 31 for the upcoming year: 2017 2016 Domestic and international equity securities 24 % 25 % Short-to-intermediate fixed income securities 60 57 Alternative investments 9 13 Cash 7 5 Total 100 % 100 % The following tables present, for each of the fair value hierarchy levels, NSP-Wisconsin’s proportionate allocation of the total postretirement benefit plan assets that are measured at fair value as of Dec. 31, 2017 and 2016 : Dec. 31, 2017 (Thousands of Dollars) Level 1 Level 2 Level 3 Investments Measured at NAV Total Cash equivalents $ 68 $ — $ — $ — $ 68 Insurance contracts — 115 — — 115 Commingled funds: U.S. equity funds 172 — — — 172 U.S fixed income funds 79 — — — 79 Emerging market debt funds 94 — — — 94 Debt securities: Government securities — 134 — — 134 U.S. corporate bonds — 147 — — 147 Non U.S. corporate bonds — 50 — — 50 Asset-backed securities — 54 — — 54 Mortgage-backed securities — 80 — — 80 Equity securities: Non U.S. equities 82 — — — 82 Other — 3 — — 3 Total $ 495 $ 583 $ — $ — $ 1,078 Dec. 31, 2016 (Thousands of Dollars) Level 1 Level 2 Level 3 Investments Measured at NAV Total Cash equivalents $ 25 $ — $ — $ — $ 25 Insurance contracts — 58 — — 58 Commingled funds: U.S. equity funds 67 — — — 67 U.S fixed income funds 33 — — — 33 Emerging market debt funds 38 — — — 38 Other commingled funds — — — 67 67 Debt securities: Government securities — 46 — — 46 U.S. corporate bonds — 77 — — 77 Non U.S. corporate bonds — 21 — — 21 Asset-backed securities — 23 — — 23 Mortgage-backed securities — 36 — — 36 Equity securities: Non U.S. equities 50 — — — 50 Other — 2 — — 2 Total $ 213 $ 263 $ — $ 67 $ 543
Change in Projected Benefit Obligation	A comparison of the actuarially computed benefit obligation and plan assets for NSP-Wisconsin is presented in the following table: (Thousands of Dollars) 2017 2016 Change in Projected Benefit Obligation: Obligation at Jan. 1 $ 14,973 $ 14,718 Service cost 29 24 Interest cost 590 651 Medicare subsidy reimbursements — 7 Plan participants’ contributions 71 87 Actuarial loss 2,069 775 Benefit payments (1,368 ) (1,289 ) Obligation at Dec. 31 $ 16,364 $ 14,973
Change in Fair Value of Plan Assets	(Thousands of Dollars) 2017 2016 Change in Fair Value of Plan Assets: Fair value of plan assets at Jan. 1 $ 543 $ 418 Actual loss on plan assets (6 ) (12 ) Plan participants’ contributions 71 87 Employer contributions 1,838 1,339 Benefit payments (1,368 ) (1,289 ) Fair value of plan assets at Dec. 31 $ 1,078 $ 543
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost	(Thousands of Dollars) 2017 2016 Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost: Net loss $ 10,553 $ 8,883 Prior service credit (1,783 ) (2,134 ) Total $ 8,770 $ 6,749
Amounts Not Yet Recognized as Components of Net Periodic Benefit Costs Recorded on the Balance Sheet Based Upon Expected Recovery in Rates	(Thousands of Dollars) 2017 2016 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 $ 110 $ — Noncurrent regulatory assets 8,660 6,749 Total $ 8,770 $ 6,749
Schedule of Assumptions Used	Measurement date Dec. 31, 2017 Dec. 31, 2016 2017 2016 Significant Assumptions Used to Measure Benefit Obligations: Discount rate for year-end valuation 3.62 % 4.13 % Mortality table RP 2014 RP 2014 Health care costs trend rate — initial Pre-65 7.00 % 5.50 % Health care costs trend rate — initial Post-65 5.50 % 5.50 % 2017 2016 2015 Significant Assumptions Used to Measure Costs: Discount rate 4.13 % 4.65 % 4.08 % Expected average long-term rate of return on assets 5.80 5.80 5.80
Effects of One-Percent Change in Assumed Health Care Cost Trend Rate	A one-percent change in the assumed health care cost trend rate would have the following effects on NSP-Wisconsin: One-Percentage Point (Thousands of Dollars) Increase Decrease APBO $ 1,588 $ (1,344 ) Service and interest components 65 (55 )
Components of Net Periodic Benefit Costs	The components of NSP-Wisconsin’s net periodic postretirement benefit costs were: (Thousands of Dollars) 2017 2016 2015 Service cost $ 29 $ 24 $ 29 Interest cost 590 651 653 Expected return on plan assets (31 ) (24 ) (30 ) Amortization of prior service credit (351 ) (351 ) (351 ) Amortization of net loss 436 330 456 Net periodic postretirement benefit cost $ 673 $ 630 $ 757

Other Income, Net (Tables)

Other Income, Net (Tables)	12 Months Ended
	Dec. 31, 2017
Other Income and Expenses [Abstract]
Other Income, Net	Other income, net for the years ended Dec. 31 consisted of the following: (Thousands of Dollars) 2017 2016 2015 Interest income $ 716 $ 244 $ 332 Other nonoperating income 325 208 789 Insurance policy (expense) income (195 ) 22 (228 ) Other nonoperating expense (13 ) (13 ) (10 ) Other income, net $ 833 $ 461 $ 883

Fair Value of Financial Asset36

Fair Value of Financial Assets and Liabilities (Tables)	12 Months Ended
	Dec. 31, 2017
Fair Value Disclosures [Abstract]
Gross Notional Amounts of Commodity Forwards and Options	The following table details the gross notional amounts of commodity options at Dec. 31: (Amounts in Thousands) (a)(b) 2017 2016 MMBtu of natural gas 42 255 (a) Amounts are not reflective of net positions in the underlying commodities. (b) Notional amounts for options are 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	Financial Impact of Qualifying Cash Flow Hedges — The impact of qualifying interest rate cash flow hedges on NSP-Wisconsin’s accumulated other comprehensive loss, included in the consolidated statements of common stockholder’s equity and in the consolidated statements of comprehensive income, is detailed in the following table: (Thousands of Dollars) 2017 2016 2015 Accumulated other comprehensive loss related to cash flow hedges at Jan. 1 $ (133 ) $ (209 ) $ (285 ) After-tax net realized losses on derivative transactions reclassified into earnings 76 76 76 Accumulated other comprehensive loss related to cash flow hedges at Dec. 31 $ (57 ) $ (133 ) $ (209 )
Derivative Assets and Liabilities Measured at Fair Value on a Recurring Basis by Hierarchy Level	Recurring Fair Value Measurements — The following table presents for each of the fair value hierarchy levels, NSP-Wisconsin’s derivative assets and liabilities measured at fair value on a recurring basis: Dec. 31, 2017 Fair Value Fair Value Total Counterparty Netting (a) (Thousands of Dollars) Level 1 Level 2 Level 3 Total (b) Current derivative assets Natural gas commodity $ — $ 14 $ — $ 14 $ — $ 14 Dec. 31, 2016 Fair Value Fair Value Total Counterparty Netting (a) (Thousands of Dollars) Level 1 Level 2 Level 3 Total (b) Current derivative assets Natural gas commodity $ — $ 149 $ — $ 149 $ — $ 149 (a) NSP-Wisconsin nets derivative instruments and related collateral in its consolidated balance sheet 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, 2017 and 2016. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements. (b) Included in the prepayments balance of $3.5 million and $3.1 million at Dec. 31, 2017 and 2016, respectively, in the consolidated balance sheets.
Carrying Amount and Fair Value of Long-term Debt	As of Dec. 31, 2017 and 2016, other financial instruments for which the carrying amount did not equal fair value were as follows: 2017 2016 (Thousands of Dollars) Carrying Amount Fair Value Carrying Amount Fair Value Long-term debt, including current portion $ 761,180 $ 856,106 $ 663,069 $ 730,284

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2017
Commitments and Contingencies Disclosure [Abstract]
Estimated Minimum Purchases Under Fuel Contracts	The estimated minimum purchases for NSP-Wisconsin under these contracts as of Dec. 31, 2017 are as follows: (Millions of Dollars) Coal Natural gas Natural gas 2018 $ 6.4 $ 9.4 $ 13.3 2019 0.6 0.4 12.3 2020 0.6 0.3 10.1 2021 0.7 0.3 9.5 2022 0.7 0.2 8.2 Thereafter 0.7 — 30.5 Total (a) $ 9.7 $ 10.6 $ 83.9 (a) Excludes additional amounts allocated to NSP-Wisconsin through intercompany charges.
Future Commitments Under Operating Leases	Future commitments under operating leases are: (Millions of Dollars) 2018 $ 0.9 2019 0.9 2020 0.9 2021 0.8 2022 0.8 Thereafter 4.6 Total $ 8.9
Low-income Housing Limited Partnerships	Amounts reflected in NSP-Wisconsin’s consolidated balance sheets for low-income housing limited partnerships include the following: (Thousands of Dollars) Dec. 31, 2017 Dec. 31, 2016 Current assets $ 426 $ 375 Property, plant and equipment, net 1,882 2,025 Other noncurrent assets 137 125 Total assets $ 2,445 $ 2,525 Current liabilities $ 1,214 $ 1,269 Mortgages and other long-term debt payable 486 486 Other noncurrent liabilities 56 54 Total liabilities $ 1,756 $ 1,809
Guarantee Issued and Outstanding	The following table presents the guarantee issued and outstanding for NSP-Wisconsin: (Millions of Dollars) Guarantee Current Term or Triggering Guarantee of customer loans for the Farm Rewiring Program (a) $ 1.0 $ — 2020 (b) (a) The term of this guarantee expires in 2020 , which is the final scheduled repayment date for the loans. As of Dec. 31, 2017, no claims had been made by the lender. (b) The debtor becomes the subject of bankruptcy or other insolvency proceedings.
Asset Retirement Obligations	A reconciliation of NSP-Wisconsin’s AROs for the years ended Dec. 31, 2017 and 2016 is as follows: (Thousands of Dollars) Beginning Balance Liabilities Recognized Accretion Cash Flow Revisions Ending Balance Dec. 31, 2017 (a) Electric plant Steam production asbestos $ 2,194 $ 949 (b) $ 50 $ — $ 3,193 Steam production ash containment 452 — 15 — 467 Electric distribution 32 — 3 — 35 Other 376 — 12 — 388 Natural gas plant Gas distribution 8,293 — 339 1,661 (c) 10,293 Common and other property Common miscellaneous 45 — 2 — 47 Total liability (d) $ 11,392 $ 949 $ 421 $ 1,661 $ 14,423 (a) There were no ARO liabilities settled during the year ended Dec. 31, 2017. (b) The liability recognized relates to asbestos at the French Island plant. (c) Changes in the gas distribution ARO are mainly related to increased labor costs. (d) Included in other long-term liabilities balance in the consolidated balance sheet. (Thousands of Dollars) Beginning Balance Liabilities Settled Accretion Cash Flow Revisions Ending Balance Dec. 31, 2016 (a) Electric plant Steam production asbestos $ 2,145 $ — $ 49 $ — $ 2,194 Steam production ash containment 617 — 18 (183 ) 452 Electric distribution 72 — 3 (43 ) 32 Other 391 (29 ) 14 — 376 Natural gas plant Gas distribution 6,367 — 256 1,670 8,293 Common and other property Common miscellaneous 95 — 2 (52 ) 45 Total liability (b) $ 9,687 $ (29 ) $ 342 $ 1,392 $ 11,392 (a) There were no ARO liabilities recognized during the year ended Dec. 31, 2016. (b) Included in other long-term liabilities balance in the consolidated balance sheet.

Regulatory Assets and Liabili38

Regulatory Assets and Liabilities (Tables)	12 Months Ended
	Dec. 31, 2017
Regulatory Assets and Liabilities Disclosure [Abstract]
Regulatory Assets	The components of regulatory assets shown on the consolidated balance sheets of NSP-Wisconsin at Dec. 31, 2017 and 2016 are: (Thousands of Dollars) See Note(s) Remaining Dec. 31, 2017 Dec. 31, 2016 Regulatory Assets Current Noncurrent Current Noncurrent Environmental remediation costs 1, 11 Various $ 16,006 $ 136,146 $ 10,669 $ 148,880 Pension and retiree medical obligations (a) 7 Various 5,674 87,505 5,989 93,160 Excess deferred taxes - TCJA 6 Various — 22,605 — — State commission adjustments 1 Plant lives 716 15,932 703 14,008 Recoverable deferred taxes on AFUDC recorded in plant (b) 1 Plant lives — 14,286 — 22,345 Losses on reacquired debt 4 Term of related debt 655 2,678 801 3,333 Other Various 62 3,065 — 4,462 Total regulatory assets $ 23,113 $ 282,217 $ 18,162 $ 286,188 (a) Includes the non-qualified pension plan. (b) Includes a write-down of $11.3 million as a result of the revaluation of deferred tax gross up at the new federal tax rate at Dec. 31, 2017.
Regulatory Liabilities	The components of regulatory liabilities shown on the consolidated balance sheets of NSP-Wisconsin at Dec. 31, 2017 and 2016 are: (Thousands of Dollars) See Note(s) Remaining Dec. 31, 2017 Dec. 31, 2016 Regulatory Liabilities Current Noncurrent Current Noncurrent Excess deferred taxes - TCJA (a) 6 Various $ — $ 236,589 $ — $ — Plant removal costs 11 Plant lives — 146,370 — 139,735 Deferred electric production and natural gas costs 1 Less than one year 13,950 — 11,377 — DOE settlement 11 Less than one year 5,261 — 4,822 — Other Various 1,501 3,848 1,229 8,454 Total regulatory liabilities $ 20,712 $ 386,807 $ 17,428 $ 148,189 (a) Primarily relates to the revaluation of recoverable/regulated plant ADIT and $41.0 million revaluation impact of non-plant ADIT at Dec. 31, 2017.

Other Comprehensive Income (Tab

Other Comprehensive Income (Tables)	12 Months Ended
	Dec. 31, 2017
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, 2017 and 2016 were as follows: Gains and Losses on Cash Flow Hedges (Thousands of Dollars) Year Ended Dec. 31, 2017 Year Ended Dec. 31, 2016 Accumulated other comprehensive loss at Jan. 1 $ (133 ) $ (209 ) Losses reclassified from net accumulated other comprehensive loss 76 76 Net current period other comprehensive income 76 76 Adoption of ASU No. 2018-02 (a) (12 ) — Accumulated other comprehensive loss at Dec. 31 $ (69 ) $ (133 )
Reclassifications out of Accumulated Other Comprehensive Loss	Reclassifications from accumulated other comprehensive loss for the years ended Dec. 31, 2017 and 2016 were as follows: Amounts Reclassified from Accumulated (Thousands of Dollars) Year Ended Dec. 31, 2017 Year Ended Dec. 31, 2016 Losses on cash flow hedges: Interest rate derivatives $ 126 (a) $ 127 (a) Total, pre-tax 126 127 Tax benefit (50 ) (51 ) Total amounts reclassified, net of tax $ 76 $ 76 (a) Included in interest charges.

Segments and Related Informat40

Segments and Related Information (Tables)	12 Months Ended
	Dec. 31, 2017
Segment Reporting [Abstract]
Results from Operations by Reportable Segment	(Thousands of Dollars) Regulated Electric Regulated Natural Gas All Other Reconciling Eliminations Consolidated Total 2017 Operating revenues (a) $ 881,891 $ 122,353 $ 1,207 $ — $ 1,005,451 Intersegment revenues 497 287 — (784 ) — Total revenues $ 882,388 $ 122,640 $ 1,207 $ (784 ) $ 1,005,451 Depreciation and amortization $ 88,946 $ 22,070 $ 200 $ — $ 111,216 Interest charges and financing costs 29,396 2,761 23 — 32,180 Income tax expense 38,866 4,040 1,266 — 44,172 Net income 70,876 7,832 708 — 79,416 (Thousands of Dollars) Regulated Electric Regulated Natural Gas All Other Reconciling Eliminations Consolidated Total 2016 Operating revenues (a) $ 849,946 $ 106,157 $ 1,130 $ — $ 957,233 Intersegment revenues 397 487 — (884 ) — Total revenues $ 850,343 $ 106,644 $ 1,130 $ (884 ) $ 957,233 Depreciation and amortization $ 81,299 $ 16,794 $ 201 $ — $ 98,294 Interest charges and financing costs 29,749 2,855 25 — 32,629 Income tax expense (benefit) 40,547 2,445 (90 ) — 42,902 Net income (loss) 65,002 4,503 (370 ) — 69,135 (Thousands of Dollars) Regulated Electric Regulated Natural Gas All Other Reconciling Eliminations Consolidated Total 2015 Operating revenues (a) $ 834,998 $ 120,147 $ 1,396 $ — $ 956,541 Intersegment revenues 419 498 — (917 ) — Total revenues $ 835,417 $ 120,645 $ 1,396 $ (917 ) $ 956,541 Depreciation and amortization $ 77,036 $ 14,034 $ 175 $ — $ 91,245 Interest charges and financing costs 26,494 2,637 90 — 29,221 Income tax expense 40,654 2,501 1,083 — 44,238 Net income 69,398 4,862 376 — 74,636 (a) Operating revenues include $177 million , $170 million and $163 million of intercompany revenue for the years ended Dec. 31, 2017 , 2016 and 2015 respectively. See Note 15 for further discussion of related party transactions by operating segment.

Related Party Transactions (Tab

Related Party Transactions (Tables)	12 Months Ended
	Dec. 31, 2017
Related Party Transactions [Abstract]
Related Party Transactions	The table below contains significant affiliate transactions among the companies and related parties including billings under the Interchange Agreement for the years ended Dec. 31: (Thousands of Dollars) 2017 2016 2015 Operating revenues: Electric $ 177,234 $ 170,483 $ 163,255 Operating expenses: Purchased power 421,609 413,615 419,028 Transmission expense 68,613 61,920 54,070 Natural gas purchased for resale 47 41 45 Other operating expenses — paid to Xcel Energy Services Inc. 92,715 106,454 93,890 Interest expense 7 4 2 Accounts receivable and payable with affiliates at Dec. 31 were: 2017 2016 (Thousands of Dollars) Accounts Accounts Accounts Accounts NSP-Minnesota $ — $ 17,825 $ — $ 18,567 PSCo — 61 — 974 SPS — 7 333 — Other subsidiaries of Xcel Energy Inc. 3,391 11,735 — 9,496 $ 3,391 $ 29,628 $ 333 $ 29,037

Summarized Quarterly Financia42

Summarized Quarterly Financial Data (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2017
Quarterly Financial Information Disclosure [Abstract]
Summarized Quarterly Financial Data (Unaudited)	Quarter Ended (Thousands of Dollars) March 31, 2017 June 30, 2017 Sept. 30, 2017 Dec. 31, 2017 Operating revenues $ 264,931 $ 230,026 $ 247,511 $ 262,983 Operating income 42,775 29,067 38,392 37,994 Net income 22,419 14,241 22,325 20,431 Quarter Ended (Thousands of Dollars) March 31, 2016 June 30, 2016 Sept. 30, 2016 Dec. 31, 2016 Operating revenues $ 254,850 $ 219,173 $ 246,144 $ 237,066 Operating income 35,448 27,778 46,342 30,360 Net income 17,631 12,625 24,221 14,658

Summary of Significant Accoun43

Summary of Significant Accounting Policies (Details)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Accounting Policies [Abstract]
Percentage of Average Annual Operating Revenues	1.20%
Number of Years Annual Operating Revenues are Averaged	3 years
Property, Plant and Equipment [Abstract]
Depreciation expense expressed as a percentage of average depreciable property	3.40%	3.30%	3.40%
Cash and Cash Equivalents [Abstract]
Maximum number of months of remaining maturity at time of purchase to consider investments in certain instruments as cash equivalents	3 months

Selected Balance Sheet Data, Ac

Selected Balance Sheet Data, Accounts Receivable (Details) - USD ($) $ in Thousands		Dec. 31, 2017	Dec. 31, 2016
Accounts Receivable, Net
Accounts receivable		$ 68,073	$ 58,896
Less allowance for bad debts		(4,873)	(4,865)
Accounts receivable, net	[1]	$ 63,200	$ 54,031
[1]	Accounts receivable, net includes $3.4 million and an immaterial amount due from affiliates for 2017 and 2016, respectively.

Selected Balance Sheet Data, In

Selected Balance Sheet Data, Inventory (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Public Utilities, Inventory [Line Items]
Inventories	$ 17,758	$ 18,309
Materials and supplies
Public Utilities, Inventory [Line Items]
Inventories	6,916	6,582
Fuel
Public Utilities, Inventory [Line Items]
Inventories	3,866	4,743
Natural gas
Public Utilities, Inventory [Line Items]
Inventories	$ 6,976	$ 6,984

Selected Balance Sheet Data, Pr

Selected Balance Sheet Data, Property, Plant and Equipment (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Public Utility, Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	$ 3,259,269	$ 3,069,525
Less accumulated depreciation	(1,170,541)	(1,121,888)
Property, plant and equipment, net	2,088,728	1,947,637
Electric plant
Public Utility, Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	2,602,671	2,499,401
Natural gas plant
Public Utility, Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	326,723	294,986
Common and other property
Public Utility, Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	181,105	156,316
CWIP
Public Utility, Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	$ 148,770	$ 118,822

Borrowings and Other Financin47

Borrowings and Other Financing Instruments, Commercial Paper (Details) - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Short-term Debt [Line Items]
Amount outstanding at period end	$ 11,000	$ 11,000	$ 60,000
Commercial Paper
Short-term Debt [Line Items]
Borrowing limit	150,000	150,000	150,000	$ 150,000
Amount outstanding at period end	11,000	11,000	60,000	10,000
Average amount outstanding	70,000	52,000	15,000	39,000
Maximum amount outstanding	$ 129,000	$ 129,000	$ 64,000	$ 122,000
Weighted average interest rate, computed on a daily basis (percentage)	1.38%	1.23%	0.69%	0.44%
Weighted average interest rate at period end (percentage)	1.73%	1.73%	0.95%	0.70%

Borrowings and Other Financin48

Borrowings and Other Financing Instruments, Letters of Credit (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Line of Credit Facility [Line Items]
Amount outstanding at period end	$ 11,000	$ 60,000
Letter of Credit
Line of Credit Facility [Line Items]
Amount outstanding at period end	$ 0	$ 0
Letter of Credit | Letter of Credit
Line of Credit Facility [Line Items]
Term of letters of credit (in years)	1 year

Borrowings and Other Financin49

Borrowings and Other Financing Instruments, Credit Facility (Details) - USD ($)		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016
Line of Credit Facility [Line Items]
Line Of Credit Facility Maximum Debt To Total Capitalization Ratio Allowed		65.00%
Line Of Credit Facility Debt To Total Capitalization Ratio		47.00%	47.00%
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		$ 75,000,000
Direct advances on the credit facility outstanding		$ 0	$ 0
Credit Facility
Line of Credit Facility [Line Items]
Debt instrument, maturity date		Jun. 30, 2021
Credit facility	[1]	$ 150,000,000
Drawn	[2]	11,000,000
Available		$ 139,000,000
Term Of Each Additional Period Revolving Termination Date Can Be Extended Subject To Majority Bank Group Approval		1 year
[1]	This credit facility matures in June 2021.
[2]	Includes outstanding commercial paper.

Borrowings and Other Financin50

Borrowings and Other Financing Instruments, Intercompany Borrowing Arrangements and Other Short-Term Borrowings (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Short-term Debt [Line Items]
Notes payable to affiliates	$ 500	$ 500
Notes Payable, Other Payables
Short-term Debt [Line Items]
Notes payable to affiliates	$ 500	$ 500
Weighted average interest rate at period end (percentage)	1.73%	0.95%

Borrowings and Other Financin51

Borrowings and Other Financing Instruments Borrowings and Other Financing Instruments, Long-Term Borrowings and Other Financing Instruments (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Long-term Debt, Maturities, Repayments in Next Twelve Months	$ 151
Long-term Debt, Maturities, Repayments of Principal in Year Four	19
Long-term Debt, Maturities, Repayments of Principal in Year Five	1
Deferred Finance Costs, Noncurrent, Net	7	$ 5
Maximum annual dividends that can be paid if equity capitalization ratio condition is not met	$ 53
Minimum calendar year average equity to total capitalization ratio authorized by state commission	52.50%	52.50%
Calendar year average equity to total capitalization ratio	53.10%
Unrestricted Retained Earnings Per State Regulatory Commissions Dividend Restrictions	$ 19
Expected equity to total capitalization ratio for the next fiscal year	51.50%
First Mortgage Bonds | Series Due Dec. 1, 2047
Debt Instrument [Line Items]
Interest Rate, Stated Percentage	3.75%
Maturity Date	Dec. 1, 2047
NSP-Wisconsin | First Mortgage Bonds | Series Due Dec. 1, 2047
Debt Instrument [Line Items]
Face Amount	$ 100
Interest Rate, Stated Percentage	3.75%
Maturity Date	Dec. 1, 2047

Joint Ownership of Transmissi52

Joint Ownership of Transmission Facilities (Details) $ in Thousands	Dec. 31, 2017USD ($)
Jointly Owned Utility Plant [Abstract]
Plant in service	$ 162,108
Accumulated depreciation	12,205
Construction work in progress	204,690
CapX2020 Transmission | Electric Transmission
Jointly Owned Utility Plant [Abstract]
Plant in service	162,108
Accumulated depreciation	12,205
Construction work in progress	$ 103,144
Ownership % (in hundredths)	81.00%
La Crosse, Wis. to Madison, Wis. | Electric Transmission
Jointly Owned Utility Plant [Abstract]
Plant in service	$ 0
Accumulated depreciation	0
Construction work in progress	$ 101,546
Ownership % (in hundredths)	37.00%

Income Taxes (Details)

Income Taxes (Details) - USD ($)		1 Months Ended	3 Months Ended		12 Months Ended
		Dec. 31, 2017	Sep. 30, 2017	Sep. 30, 2015	Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015		Dec. 31, 2012	Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2014
Income Tax Examination [Line Items]
Tax Cuts and Jobs Act of 2017, Corporate Federal Tax Rate		21.00%
Tax Cuts and Jobs Act of 2017, Net Operating Loss Deduction Limitation, Percent of Taxable income		80.00%
Tax Cuts and Jobs Act of 2017, Incomplete Accounting, Change in Tax Rate, Regulatory Liability, Provisional Income Tax (Expense) Benefit, Gross					$ 210,000,000
Tax Cuts and Jobs Act of 2017, Incomplete Accounting, Change in Tax Rate, Net Income Reduction					$ 1,000,000
Consolidated Appropriations Act of 2016 [Abstract]
Excise Tax Delay					2 years
Unrecognized Tax Benefits [Abstract]
Unrecognized Tax Benefits - Permanent tax positions											$ 1,400,000	$ 400,000
Unrecognized tax benefit — Temporary tax positions											1,000,000	4,900,000
Total unrecognized tax benefit		$ 2,400,000			$ 5,300,000	$ 4,500,000		$ 3,000,000			2,400,000	5,300,000		$ 3,000,000
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Balance at Jan. 1					5,300,000	4,500,000		3,000,000
Unrecognized Tax Benefits, Increase Resulting from Current Period Tax Positions					400,000	500,000		1,900,000
Unrecognized Tax Benefits, Decrease Resulting from Current Period Tax Positions					(300,000)	0		(300,000)
Unrecognized Tax Benefits Increases Resulting From Prior Period Tax Positions					1,300,000	500,000		800,000
Unrecognized Tax Benefits Decreases Resulting From Prior Period Tax Positions					(4,300,000)	(200,000)		(900,000)
Balance at Dec. 31		$ 2,400,000			$ 2,400,000	$ 5,300,000		$ 4,500,000
Tax Benefits Associated With NOL And Tax Credit Carryforwards [Abstract]
NOL and tax credit carryforwards											(1,900,000)	(1,200,000)
Decrease in Unrecognized Tax Benefits is Reasonably Possible											1,000,000
Amounts accrued for penalties related to unrecognized tax benefits											0	0		$ 0
Effective Income Tax Rate Reconciliation, Percent [Abstract]
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent					35.00%	35.00%	[1]	35.00%	[1]
Effective Income Tax Rate Reconciliation, State and Local Income Taxes, Percent					5.10%	5.10%	[1]	5.10%	[1]
Effective Income Tax Reconciliation, Adjustments Attributable to Tax Returns, Percent					(2.30%)	(0.30%)	[1]	(0.40%)	[1]
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Percent	[2]				(0.10%)	(0.20%)	[1]	(0.20%)	[1]
Effective Income Tax Rate Reconciliation, Other Regulatory Items, Percent					(1.70%)	(0.60%)	[1]	(1.80%)	[1]
Effective Income Tax Rate Reconciliation Regulatory Differences Utility Plant Items, Percent					(1.00%)	(0.70%)	[1]	(0.70%)	[1]
Effective Income Tax Rate Reconciliation Change In Unrecognized Tax Benefits, Percent					0.80%	0.10%	[1]	0.10%	[1]
Effective Income Tax Rate Reconciliation, Other Adjustments, Percent					(0.10%)	(0.10%)	[1]	0.10%	[1]
Effective Income Tax Rate Reconciliation, Percent					35.70%	38.30%	[1]	37.20%	[1]
Components of Income Tax Expense (Benefit), Continuing Operations [Abstract]
Current Federal Tax Expense (Benefit)					$ 2,765,000	$ 5,367,000		$ (4,715,000)
Current State and Local Tax Expense (Benefit)					(1,000)	131,000		2,150,000
Current Change In Unrecognized Tax Expense (Benefit)					(3,626,000)	559,000		1,498,000
Deferred Federal Income Tax Expense (Benefit)					32,919,000	29,588,000		40,580,000
Deferred State and Local Income Tax Expense (Benefit)					7,972,000	8,212,000		6,675,000
Deferred Change In Unrecognized Tax Expense (Benefit)					4,666,000	(432,000)		(1,422,000)
Deferred investment tax credits					(523,000)	(523,000)		(528,000)
Income Tax Expense (Benefit)					44,172,000	42,902,000		44,238,000
Deferred Income Tax Expense (Benefit), Continuing Operations [Abstract]
Deferred tax expense (benefit) excluding selected items					(173,906,000)	39,530,000		51,084,000
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities					219,514,000	(2,112,000)		(5,200,000)
Other Comprehensive Income (Loss), Tax					(51,000)	(50,000)		(51,000)
Deferred Income Tax Expense (Benefit)					45,557,000	$ 37,368,000		$ 45,833,000
Deferred Tax Liabilities, Gross [Abstract]
Deferred Tax Liabilities, Property, Plant and Equipment											270,425,000	412,071,000	[3]
Deferred Tax Liabilities, Regulatory Assets											58,436,000	63,825,000	[3]
Deferred Tax Liabilities, Compensation and Benefits, Employee Benefits											14,245,000	21,575,000	[3]
Deferred Tax Liabilities, Other											6,855,000	9,666,000	[3]
Deferred Tax Liabilities, Gross											349,961,000	507,137,000	[3]
Deferred Tax Assets, Gross [Abstract]
Deferred Tax Assets Regulatory Liabilities											55,768,000	(5,788,000)	[3]
Deferred Tax Assets, Operating Loss Carryforwards											12,606,000	35,216,000	[3]
Deferred Tax Assets Environmental Remediation											8,068,000	25,842,000	[3]
Deferred Tax Assets Tax credit carryforward											4,644,000	3,704,000	[3]
Deferred Tax Assets, Tax Deferred Expense, Compensation and Benefits, Employee Benefits											3,868,000	6,132,000	[3]
Deferred Tax Assets Deferred Investment Tax Credits											3,175,000	4,996,000	[3]
Deferred Tax Assets, Other											5,145,000	6,442,000	[3]
Deferred Tax Assets, Net of Valuation Allowance											93,274,000	76,544,000	[3]
Deferred Tax Liabilities, Net											256,687,000	430,593,000	[3]
Internal Revenue Service (IRS)
Tax Audits [Abstract]
Year(s) under examination				2012 and 2013						2010 and 2011
Year of carryback claim under examination										2,009
Tax Adjustments, Settlements, and Unusual Provisions					$ 14,000,000
Tax years under examination, Concluded			2012 and 2013
Operating Loss Carryforwards											58,000,000	97,000,000
Tax Credit Carryforward, Amount											4,000,000	4,000,000
Carryforward expiration date range, low					2,021
Carryforward expiration date range, high					2,037
Consolidated Appropriations Act of 2016 [Abstract]
Earliest Open Tax Year Subject To Examination					2,009
WISCONSIN
Tax Audits [Abstract]
Year(s) under examination						2012 and 2013
Consolidated Appropriations Act of 2016 [Abstract]
Earliest Open Tax Year Subject To Examination					2,012
State and Local Jurisdiction
Tax Audits [Abstract]
Operating Loss Carryforwards											$ 5,000,000	$ 3,000,000
Carryforward expiration date range, low					2,021
Carryforward expiration date range, high					2,032
Consolidated Appropriations Act of 2016; 2015, 2016, 2017 Impact [Member]
Consolidated Appropriations Act of 2016 [Abstract]
Bonus depreciation rate, Percent											50.00%
Consolidated Appropriations Act of 2016; 2018 Impact [Member]
Consolidated Appropriations Act of 2016 [Abstract]
Production Tax Credit Rate, Percent											60.00%
Consolidated Appropriations Act of 2016; 2019 Impact [Member]
Consolidated Appropriations Act of 2016 [Abstract]
Production Tax Credit Rate, Percent											40.00%
Investment Tax Credit Rate, Percent											30.00%
Consolidated Appropriations Act of 2016; 2016 Impact [Member]
Consolidated Appropriations Act of 2016 [Abstract]
Production Tax Credit Rate, Percent											100.00%
Consolidated Appropriations Act of 2016; 2017 Impact [Member]
Consolidated Appropriations Act of 2016 [Abstract]
Production Tax Credit Rate, Percent											80.00%
Consolidated Appropriations Act of 2016; 2020 Impact [Member]
Consolidated Appropriations Act of 2016 [Abstract]
Investment Tax Credit Rate, Percent											26.00%
Consolidated Appropriations Act of 2016; 2021 Impact [Member]
Consolidated Appropriations Act of 2016 [Abstract]
Investment Tax Credit Rate, Percent											22.00%
Consolidated Appropriations Act of 2016; After 2021 Impact [Member]
Consolidated Appropriations Act of 2016 [Abstract]
Investment Tax Credit Rate, Percent											10.00%
Plant Related Regulatory Liability [Member]
Income Tax Examination [Line Items]
Tax Cuts and Jobs Act of 2017, Incomplete Accounting, Change in Tax Rate, Regulatory Liability, Provisional Income Tax (Expense) Benefit					$ 149,000,000
Non-Plant Related Regulated Liability [Member]
Income Tax Examination [Line Items]
Tax Cuts and Jobs Act of 2017, Incomplete Accounting, Change in Tax Rate, Regulatory Liability, Provisional Income Tax (Expense) Benefit					41,000,000
Non-Plant Related Regulatory Asset [Member]
Income Tax Examination [Line Items]
Tax Cuts and Jobs Act of 2017, Incomplete Accounting, Change in Tax Rate, Regulatory Asset, Provisional Income Tax Expense (Benefit)					$ 23,000,000
[1]	The prior periods included in this footnote have been reclassified to conform to current year presentation.
[2]	The amortization of excess deferred taxes.
[3]	The prior period included in this footnote has been reclassified to conform to current year presentation.

Benefit Plans and Other Postr54

Benefit Plans and Other Postretirement Benefits, Employees Represented by Local Labor Unions (Details)	Dec. 31, 2017Employee
Employees Represented by Local Labor Unions Under Collective Bargaining Agreements Receiving Benefits [Abstract]
Approximate percent of employees receiving benefits who are represented by local labor unions under collective bargaining agreements (as a percent)	71.00%
Number of bargaining employees receiving benefits under several collective bargaining agreements	383

Benefit Plans and Other Postr55

Benefit Plans and Other Postretirement Benefits Benefits Plans and Other Postretirement Benefits, Fair Value Hierarchy (Details)	12 Months Ended
	Dec. 31, 2017
Commingled funds | Maximum
Defined Benefit Plan Disclosure [Line Items]
Notice period for investment redemption	90 days
Real estate funds | Minimum
Defined Benefit Plan Disclosure [Line Items]
Notice period for investment redemption	45 days
Real estate funds | Maximum
Defined Benefit Plan Disclosure [Line Items]
Notice period for investment redemption	90 days

Benefit Plans and Other Postr56

Benefit Plans and Other Postretirement Benefits, Pension Benefits (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Pension Benefits [Abstract]
Minimum number of years historical achieved weighted average annual returns are used to determine investment return assumptions (in years)	20 years
Expected average long-term rate of return on assets (as a percent)	7.10%	7.10%
Expected average long-term rate of return on assets for next fiscal year (as a percent)	7.10%
Supplemental Executive Retirement Plan (SERP) and Nonqualified Pension Plan
Pension Benefits [Abstract]
Total benefit obligation	$ 1,000	$ 1,000
Pension Plan [Member]
Pension Benefits [Abstract]
Total benefit obligation	156,748	157,457	$ 152,545
Net benefit cost recognized for financial reporting	$ 10,571	$ 7,579	$ 8,711
Expected average long-term rate of return on assets (as a percent)	7.10%	7.10%	7.25%
Expected average long-term rate of return on assets for next fiscal year (as a percent)	7.10%
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (as a percent)	100.00%	100.00%
Pension Plan [Member] | Domestic and international equity securities
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (as a percent)	38.00%	40.00%
Pension Plan [Member] | Long-duration fixed income and interest rate swap securities
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (as a percent)	23.00%	23.00%
Pension Plan [Member] | Short-to-intermediate fixed income securities
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (as a percent)	21.00%	16.00%
Pension Plan [Member] | Alternative investments
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (as a percent)	16.00%	19.00%
Pension Plan [Member] | Cash
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	$ 37,000	$ 44,000
Net benefit cost recognized for financial reporting	$ 5,000	$ 8,000

Benefit Plans and Other Postr57

Benefit Plans and Other Postretirement Benefits, Fair Value of Pension Plan Assets (Details) - Pension Plan [Member] - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	$ 124,852	$ 118,976	$ 119,314
Plan asset investments measured at net asset value	45,819	43,707
Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	54,809	51,079
Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	24,224	24,190
Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Cash equivalents
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	8,091	3,939
Plan asset investments measured at net asset value	0	0
Cash equivalents | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	8,091	3,939
Cash equivalents | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Cash equivalents | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
U.S. equity funds
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	21,850	21,415
Plan asset investments measured at net asset value	0	0
U.S. equity funds | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	21,850	21,415
U.S. equity funds | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
U.S. equity funds | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Non U.S. equity funds
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	12,379	16,348
Plan asset investments measured at net asset value	8,479	8,942
Non U.S. equity funds | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	3,900	7,406
Non U.S. equity funds | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Non U.S. equity funds | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
U.S. corporate bond funds
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	14,035	10,581
Plan asset investments measured at net asset value	0	0
U.S. corporate bond funds | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	14,035	10,581
U.S. corporate bond funds | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
U.S. corporate bond funds | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Emerging market equity funds
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	13,381	8,577
Plan asset investments measured at net asset value	13,381	8,577
Emerging market equity funds | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Emerging market equity funds | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Emerging market equity funds | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Emerging market debt funds
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	10,277	7,306
Plan asset investments measured at net asset value	7,079	3,787
Emerging market debt funds | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	3,198	3,519
Emerging market debt funds | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Emerging market debt funds | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Commodity funds
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		889
Plan asset investments measured at net asset value		889
Commodity funds | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0
Commodity funds | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0
Commodity funds | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0
Private equity investments
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	3,583	4,652
Plan asset investments measured at net asset value	3,583	4,652
Private equity investments | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Private equity investments | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Private equity investments | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Real estate
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	8,309	8,108
Plan asset investments measured at net asset value	8,309	8,108
Real estate | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Real estate | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Real estate | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Other commingled funds
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	5,171	8,752
Plan asset investments measured at net asset value	4,965	8,752
Other commingled funds | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	206	0
Other commingled funds | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Other commingled funds | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Government securities
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	12,167	12,773
Plan asset investments measured at net asset value	0	0
Government securities | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Government securities | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	12,167	12,773
Government securities | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
U.S. corporate bonds
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	10,178	9,432
Plan asset investments measured at net asset value	0	0
U.S. corporate bonds | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
U.S. corporate bonds | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	10,178	9,432
U.S. corporate bonds | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Non U.S. corporate bonds
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	1,730	1,514
Plan asset investments measured at net asset value	0	0
Non U.S. corporate bonds | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Non U.S. corporate bonds | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	1,730	1,514
Non U.S. corporate bonds | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Mortgage-backed securities
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		254
Plan asset investments measured at net asset value		0
Mortgage-backed securities | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0
Mortgage-backed securities | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		254
Mortgage-backed securities | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0
Asset-backed securities
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		120
Plan asset investments measured at net asset value		0
Asset-backed securities | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0
Asset-backed securities | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		120
Asset-backed securities | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0
U.S. equities
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	4,863	4,219
Plan asset investments measured at net asset value	0	0
U.S. equities | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	4,863	4,219
U.S. equities | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
U.S. equities | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Other
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	(1,162)	97
Plan asset investments measured at net asset value	23	0
Other | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	(1,334)	0
Other | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	149	97
Other | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	$ 0	$ 0

Benefit Plans and Other Postr58

Benefit Plans and Other Postretirement Benefits, Pension Plan Benefit Obligations, Cash Flows and Benefit Costs (Details) $ in Thousands		1 Months Ended	12 Months Ended
		Jan. 31, 2018USD ($)Plan	Dec. 31, 2017USD ($)Plan	Dec. 31, 2016USD ($)Plan	Dec. 31, 2015USD ($)Plan
Components of Net Periodic Benefit Cost (Credit) [Abstract]
Settlement Charge Recognized in Operating and Maintenance Expenses			$ 205,539	$ 194,927	$ 179,413
Significant Assumptions Used to Measure Costs [Abstract]
Expected average long-term rate of return on assets (as a percent)			7.10%	7.10%
Expected average long-term rate of return on assets for next fiscal year (as a percent)			7.10%
Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Accumulated Benefit Obligation at Dec. 31			$ 145,387	$ 146,448
Change in Projected Benefit Obligation [Roll Forward]
Obligation at Jan. 1		$ 156,748	157,457	152,545
Service cost			4,618	4,417	4,759
Interest cost			6,218	6,816	6,520
Plan amendments			(713)	305
Actuarial (gain) loss			6,499	7,315
Benefit payments	[1]		(17,331)	(13,941)
Obligation at Dec. 31			156,748	157,457	152,545
Defined Benefit Plan, Plan Assets, Payment for Settlement			13,000
Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1		124,852	118,976	119,314
Actual return (loss) on plan assets			13,923	6,163
Employer contributions			9,284	7,440
Benefit payments	[1]		(17,331)	(13,941)
Fair value of plan assets at Dec. 31			124,852	118,976	119,314
Funded Status of Plans at Dec. 31 [Abstract]
Funded status	[2]		(31,896)	(38,481)
Amount Not Yet Recognized as Components of Net Periodic Benefit Cost Have Been Recorded as Follows Based Upon Expected Recovery in Rates [Abstract]
Net loss			80,429	91,531
Prior service (credit) cost			(346)	750
Total			80,083	92,281
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			5,548	5,972
Noncurrent regulatory assets			74,535	86,309
Total			$ 80,083	$ 92,281
Significant Assumptions Used to Measure Benefit Obligations [Abstract]
Discount rate for year-end valuation (as a percent)			3.63%	4.13%
Mortality table			RP 2,014	RP 2,014
Expected average long-term increase in compensation level (as a percent)			3.75%	3.75%
Cash Flows [Abstract]
Total contributions to Xcel Energy's pension plans during the period			$ 9,000	$ 7,000	5,000
Components of Net Periodic Benefit Cost (Credit) [Abstract]
Service cost			4,618	4,417	4,759
Interest cost			6,218	6,816	6,520
Expected return on plan assets			(9,180)	(9,157)	(9,483)
Amortization of prior service cost (credit)			138	111	111
Amortization of net loss			5,846	5,392	6,804
Settlement charge	[3]		7,107	0	0
Net periodic pension cost			14,747	7,579	8,711
Costs not recognized due to effects of regulation			(4,176)	0	0
Net benefit cost recognized for financial reporting			10,571	$ 7,579	$ 8,711
Settlement Charge Recognized in Operating and Maintenance Expenses			$ 2,000
Significant Assumptions Used to Measure Costs [Abstract]
Discount rate (as a percent)			4.13%	4.66%	4.11%
Expected average long-term increase in compensation level (as a percent)			3.75%	4.00%	3.75%
Expected average long-term rate of return on assets (as a percent)			7.10%	7.10%	7.25%
Allocated costs for pension plans sponsored by Xcel Energy Inc.			$ 3,000	$ 2,000	$ 2,000
Expected average long-term rate of return on assets for next fiscal year (as a percent)			7.10%
Number of years fair market value of plan assets is adjusted using calculated value method (in years)			5 years
Annual adjustment rate used in calculated value method (as a percent)			20.00%
Xcel Energy Inc. | Pension Plan [Member]
Cash Flows [Abstract]
Number of pension plans to which contributions were made | Plan			4	4	4
Total contributions to Xcel Energy's pension plans during the period			$ 162,000	$ 125,000	$ 90,000
Subsequent Event | Pension Plan [Member]
Cash Flows [Abstract]
Total contributions to Xcel Energy's pension plans during the period		$ 10,000
Subsequent Event | Xcel Energy Inc. | Pension Plan [Member]
Cash Flows [Abstract]
Number of pension plans to which contributions were made | Plan		4
Total contributions to Xcel Energy's pension plans during the period		$ 150,000
[1]	2017 amount includes approximately $13 million of lump-sum benefit payments used in the determination of a settlement charge.
[2]	Amounts are recognized in noncurrent liabilities on NSP-Wisconsin’s consolidated balance sheets.
[3]	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 the fourth quarter of 2017 as a result of lump-sum distributions during the 2017 plan year, NSP-Wisconsin recorded a total pension settlement charge of $7 million, the majority of which was not recognized due to the effects of regulation. A total of $2 million of that amount was recorded in O&M expenses in the fourth quarter of 2017.

Benefit Plans and Other Postr59

Benefit Plans and Other Postretirement Benefits, Defined Contribution Plans (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Defined Contribution Plans [Abstract]
Contributions to 401(k) and other defined contribution plans	$ 1	$ 1	$ 1

Benefit Plans and Other Postr60

Benefit Plans and Other Postretirement Benefits, Postretirement Health Care Benefits (Details) - Other Postretirement Benefits Plan [Member]	Dec. 31, 2017	Dec. 31, 2016
Postretirement Health Care Benefits [Abstract]
Target pension asset allocations (as a percent)	100.00%	100.00%
Domestic and international equity securities
Postretirement Health Care Benefits [Abstract]
Target pension asset allocations (as a percent)	24.00%	25.00%
Short-to-intermediate fixed income securities
Postretirement Health Care Benefits [Abstract]
Target pension asset allocations (as a percent)	60.00%	57.00%
Alternative investments
Postretirement Health Care Benefits [Abstract]
Target pension asset allocations (as a percent)	9.00%	13.00%
Cash
Postretirement Health Care Benefits [Abstract]
Target pension asset allocations (as a percent)	7.00%	5.00%

Benefit Plans and Other Postr61

Benefit Plans and Other Postretirement Benefits, Fair Value of Postretirement Benefit Plan Assets (Details) - Other Postretirement Benefits Plan [Member] - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	$ 1,078	$ 543	$ 418
Plan assets at net asset value	0	67
Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	495	213
Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	583	263
Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Cash equivalents
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	68	25
Plan assets at net asset value	0	0
Cash equivalents | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	68	25
Cash equivalents | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Cash equivalents | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Insurance contracts
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	115	58
Plan assets at net asset value	0	0
Insurance contracts | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Insurance contracts | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	115	58
Insurance contracts | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
U.S. equity funds
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	172	67
Plan assets at net asset value	0	0
U.S. equity funds | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	172	67
U.S. equity funds | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
U.S. equity funds | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
U.S fixed income funds
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	79	33
Plan assets at net asset value	0	0
U.S fixed income funds | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	79	33
U.S fixed income funds | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
U.S fixed income funds | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Emerging market debt funds
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	94	38
Plan assets at net asset value	0	0
Emerging market debt funds | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	94	38
Emerging market debt funds | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Emerging market debt funds | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Other commingled funds
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		67
Plan assets at net asset value		67
Other commingled funds | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0
Other commingled funds | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0
Other commingled funds | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0
Government securities
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	134	46
Plan assets at net asset value	0	0
Government securities | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Government securities | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	134	46
Government securities | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
U.S. corporate bonds
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	147	77
Plan assets at net asset value	0	0
U.S. corporate bonds | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
U.S. corporate bonds | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	147	77
U.S. corporate bonds | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Non U.S. corporate bonds
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	50	21
Plan assets at net asset value	0	0
Non U.S. corporate bonds | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Non U.S. corporate bonds | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	50	21
Non U.S. corporate bonds | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Asset-backed securities
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	54	23
Plan assets at net asset value	0	0
Asset-backed securities | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Asset-backed securities | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	54	23
Asset-backed securities | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Mortgage-backed securities
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	80	36
Plan assets at net asset value	0	0
Mortgage-backed securities | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Mortgage-backed securities | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	80	36
Mortgage-backed securities | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Non U.S. equities
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	82	50
Plan assets at net asset value	0	0
Non U.S. equities | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	82	50
Non U.S. equities | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Non U.S. equities | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Other
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	3	2
Plan assets at net asset value	0	0
Other | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Other | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	3	2
Other | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	$ 0	$ 0

Benefit Plans and Other Postr62

Benefit Plans and Other Postretirement Benefits, Postretirement Benefit Plan Benefit Obligations, Cash Flows and Benefit Costs (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Funded Status of Plans at Dec. 31 [Abstract]
Noncurrent liabilities	$ (50,027)	$ (55,164)
Significant Assumptions Used to Measure Costs [Abstract]
Expected average long-term rate of return on assets (as a percent)	7.10%	7.10%
Other Postretirement Benefits Plan [Member]
Change in Projected Benefit Obligation [Roll Forward]
Obligation at Jan. 1	$ 14,973	$ 14,718
Service cost	29	24	$ 29
Interest cost	590	651	653
Medical subsidy reimbursements	0	7
Plan participants' contributions	71	87
Actuarial (gain) loss	2,069	775
Benefit payments	(1,368)	(1,289)
Obligation at Dec. 31	16,364	14,973	14,718
Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1	543	418
Actual return (loss) on plan assets	(6)	(12)
Plan participants' contributions	71	87
Employer contributions	1,838	1,339
Benefit payments	(1,368)	(1,289)
Fair value of plan assets at Dec. 31	1,078	543	418
Funded Status of Plans at Dec. 31 [Abstract]
Funded status	(15,286)	(14,430)
Current liabilities	(269)	(822)
Noncurrent liabilities	(15,017)	(13,608)
Net postretirement amounts recognized on consolidated balance sheets	(15,286)	(14,430)
Amount Not Yet Recognized as Components of Net Periodic Benefit Cost Have Been Recorded as Follows Based Upon Expected Recovery in Rates [Abstract]
Net loss	10,553	8,883
Prior service (credit) cost	(1,783)	(2,134)
Total	8,770	6,749
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	110	0
Noncurrent regulatory assets	8,660	6,749
Total	$ 8,770	$ 6,749
Significant Assumptions Used to Measure Benefit Obligations [Abstract]
Discount rate for year-end valuation (as a percent)	3.62%	4.13%
Mortality table	RP 2,014	RP 2,014
Defined Benefit Plan, Health Care Cost Trend Rate Assumed, Pre-65	7.00%	5.50%
Defined Benefit Plan, Health Care Cost Trend Rate Assumed, Post-65	5.50%	5.50%
Ultimate health care trend assumption rate (as a percent)	4.50%
Period until ultimate trend rate is reached (in years)	5 years
Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rate [Abstract]
One-percent increase in APBO	$ 1,588
One-percent decrease in APBO	(1,344)
One-percent increase in service and interest components	65
One-percent decrease in service and interest components	(55)
Cash Flows [Abstract]
Total contributions to Xcel Energy's postretirement health care plans during the year	2,000	$ 1,000	1,000
Expected contribution to postretirement health care plans during 2018	1,000
Components of Net Periodic Benefit Cost (Credit) [Abstract]
Service cost	29	24	29
Interest cost	590	651	653
Expected return on plan assets	(31)	(24)	(30)
Amortization of prior service cost (credit)	(351)	(351)	(351)
Amortization of net loss	436	330	456
Net benefit cost recognized for financial reporting	$ 673	$ 630	$ 757
Significant Assumptions Used to Measure Costs [Abstract]
Discount rate (as a percent)	4.13%	4.65%	4.08%
Expected average long-term rate of return on assets (as a percent)	5.80%	5.80%	5.80%
Xcel Energy Inc. | Other Postretirement Benefits Plan [Member]
Cash Flows [Abstract]
Total contributions to Xcel Energy's postretirement health care plans during the year	$ 20,000	$ 18,000	$ 18,000
Expected contribution to postretirement health care plans during 2018	$ 12,000

Benefit Plans and Other Postr63

Benefit Plans and Other Postretirement Benefits, Projected Benefit Payments (Details) $ in Thousands	Dec. 31, 2017USD ($)
Pension Plan [Member]
Defined Benefit Plan, Gross Projected Benefit Payments [Abstract]
2,018	$ 11,189
2,019	11,812
2,020	12,361
2,021	11,842
2,022	11,640
2023-2027	58,627
Other Postretirement Benefits Plan [Member]
Defined Benefit Plan, Gross Projected Benefit Payments [Abstract]
2,018	1,352
2,019	1,329
2,020	1,298
2,021	1,254
2,022	1,215
2023-2027	5,111
Expected Medicare Part D Subsidies [Abstract]
2,018	5
2,019	4
2,020	3
2,021	3
2,022	3
2023-2027	14
Defined Benefit Plan, Net Projected Benefit Payments [Abstract]
2,018	1,347
2,019	1,325
2,020	1,295
2,021	1,251
2,022	1,212
2023-2027	$ 5,097

Benefit Plans and Other Postr64

Benefit Plans and Other Postretirement Benefits, Multiemployer Plans (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Multiemployer Pension Plans
Multiemployer Plans [Abstract]
Multiemployer contributions	$ 248	$ 707	$ 944

Other Income, Net (Details)

Other Income, Net (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Other Income and Expenses [Abstract]
Interest income	$ 716	$ 244	$ 332
Other nonoperating income	325	208	789
Insurance Policy Expense (Income), Net	(195)	22	(228)
Other nonoperating expense	(13)	(13)	(10)
Other income, net	$ 833	$ 461	$ 883

Fair Value of Financial Asset66

Fair Value of Financial Assets and Liabilities, Derivative Instruments (Details) MMBTU in Thousands, $ in Millions		Dec. 31, 2017USD ($)MMBTU	Dec. 31, 2016MMBTU
Interest Rate Swap
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 | $		$ (0.1)
Natural Gas Commodity (in million British thermal units)
Gross Notional Amounts of Commodity Options [Abstract]
Derivative, Nonmonetary Notional amount | MMBTU	[1],[2]	42	255
[1]	Amounts are not reflective of net positions in the underlying commodities.
[2]	Notional amounts for options are included on a gross basis, but are weighted for the probability of exercise.

Fair Value of Financial Asset67

Fair Value of Financial Assets and Liabilities, Financial Impact of Qualifying Cash Flow Hedges (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
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	$ (133)	$ (209)	$ (285)
After-tax net realized losses on derivative transactions reclassified into earnings	76	76	76
Accumulated other comprehensive loss related to cash flow hedges at Dec. 31	$ (57)	$ (133)	$ (209)

Fair Value of Financial Asset68

Fair Value of Financial Assets and Liabilities, Impact of Derivative Activity (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Financial Impact of Qualifying Fair Value Hedges on Earnings [Abstract]
Derivative instruments designated as fair value hedges	$ 0	$ 0	$ 0
Recognized gains (losses) from fair value hedges or related hedged transactions	0	0	0
Designated as Hedging Instrument | Cash Flow Hedges | Interest Rate
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract]
Interest Rate Cash Flow Hedge Gain (Loss) Reclassified to Earnings, Net	(100,000)	0	0
Other Derivative Instruments | Natural Gas Commodity
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 regulatory (assets) and liabilities	(300,000)	(200,000)	(700,000)
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities)	$ 200,000	$ 800,000	$ 1,400,000

Fair Value of Financial Asset69

Fair Value of Financial Assets and Liabilities, Derivative Assets and Liabilities at Fair Value (Details) - USD ($) $ in Thousands		Dec. 31, 2017	Dec. 31, 2016
Derivatives, Fair Value [Line Items]
Prepayments		$ 3,450	$ 3,128
Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	[1]	14	149
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset	[2]	0	0
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Assets | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		0	0
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Assets | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		14	149
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Assets | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		0	0
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis
Derivatives, Fair Value [Line Items]
Prepayments		3,500	3,100
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments | Natural Gas Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		$ 14	$ 149
[1]	Included in the prepayments balance of $3.5 million and $3.1 million at Dec. 31, 2017 and 2016, respectively, in the consolidated balance sheets.
[2]	NSP-Wisconsin nets derivative instruments and related collateral in its consolidated balance sheet 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, 2017 and 2016. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.

Fair Value of Financial Asset70

Fair Value of Financial Assets and Liabilities, Fair Value of Long-Term Debt (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Carrying Amount
Financial Liabilities, Balance Sheet Groupings [Abstract]
Long-term debt, including current portion	$ 761,180	$ 663,069
Fair Value
Financial Liabilities, Balance Sheet Groupings [Abstract]
Long-term debt, including current portion	$ 856,106	$ 730,284

Rate Matters Rate Matters (Deta

Rate Matters Rate Matters (Details) $ in Thousands

1 Months Ended

3 Months Ended

12 Months Ended

Dec. 31, 2017USD ($)

Nov. 30, 2017USD ($)

May 31, 2017USD ($)

Sep. 30, 2016

Jun. 30, 2016

Dec. 31, 2015

Feb. 28, 2015

Nov. 30, 2013

Mar. 31, 2015USD ($)

Dec. 31, 2017USD ($)

Dec. 31, 2016USD ($)

Dec. 31, 2015USD ($)MW

Dec. 31, 2013USD ($)

Dec. 31, 2008USD ($)

Public Utilities, General Disclosures [Line Items]

Loss on Monticello life cycle management/extended power uprate project

$ 0

$ 0

$ 5,237

Xcel Energy Inc. | Nuclear Project Prudency Investigation

Public Utilities, General Disclosures [Line Items]

Loss on Monticello life cycle management/extended power uprate project

$ 129,000

NSP-Wisconsin | MPSC Proceeding - Michigan 2018 Electric Rate Case

Public Utilities, General Disclosures [Line Items]

Public Utilities, Requested Rate Increase (Decrease), Amount

$ 1,000

Public Utilities, Requested Rate Increase (Decrease), Percentage

7.10%

Public Utilities, Requested Return on Equity, Percentage

10.10%

Public Utilities, Requested Equity Capital Structure, Percentage

52.50%

Public Utilities, Requested Rate Base, Amount

$ 43,000

NSP-Wisconsin | Nuclear Project Prudency Investigation

Public Utilities, General Disclosures [Line Items]

Loss on Monticello life cycle management/extended power uprate project

5,000

NSP-Wisconsin | Public Service Commission of Wisconsin (PSCW) | PSCW Proceeding - Wisconsin 2018 Electric and Natural Gas Rate Case - Electric Rates 2018 [Member]

Public Utilities, General Disclosures [Line Items]

Public Utilities, Requested Rate Increase (Decrease), Amount

$ 25,000

Public Utilities, Requested Rate Increase (Decrease), Percentage

3.60%

Public Utilities, Requested Rate Base, Amount

$ 1,200,000

Public Utilities, Approved Rate Increase (Decrease), Amount

$ 9,000

Public Utilities, Approved Rate Increase (Decrease), Percentage

1.40%

NSP-Wisconsin | Public Service Commission of Wisconsin (PSCW) | PSCW Proceeding - Wisconsin 2018 Electric and Natural Gas Rate Case - Gas Rates 2018 [Member]

Public Utilities, General Disclosures [Line Items]

Public Utilities, Requested Rate Increase (Decrease), Amount

$ 12,000

Public Utilities, Requested Rate Increase (Decrease), Percentage

10.10%

Public Utilities, Requested Rate Base, Amount

$ 138,000

Public Utilities, Approved Rate Increase (Decrease), Amount

$ 10,000

Public Utilities, Approved Rate Increase (Decrease), Percentage

8.30%

NSP-Wisconsin | Public Service Commission of Wisconsin (PSCW) | PSCW Proceeding - Wisconsin 2018 Electric and Natural Gas Rate Case [Member]

Public Utilities, General Disclosures [Line Items]

Public Utilities, Requested Return on Equity, Percentage

10.00%

Public Utilities, Requested Equity Capital Structure, Percentage

52.53%

Public Utilities, Approved Return on Equity, Percentage

9.80%

Public Utilities, Approved Equity Capital Structure, Percentage

51.45%

NSP-Minnesota | Nuclear Project Prudency Investigation

Public Utilities, General Disclosures [Line Items]

Nuclear Project Expenditures, Amount

$ 665,000

Total Capitalized Nuclear Project Costs

$ 748,000

Initial Estimated Nuclear Project Expenditures

$ 320,000

Loss on Monticello life cycle management/extended power uprate project

$ 129,000

NSP-Minnesota | FERC Proceeding, MISO ROE Complaint

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%

NSP-Minnesota | Minnesota Public Utilities Commission | Nuclear Project Prudency Investigation

Public Utilities, General Disclosures [Line Items]

Public Utilities, Amount Of Recoverable Investment, With Return

415,000

Public Utilities, Amount Of Recoverable Investment, Without A Return

$ 333,000

NSP-Minnesota | Federal Energy Regulatory Commission (FERC) | FERC Proceeding, MISO ROE Complaint

Public Utilities, General Disclosures [Line Items]

Public Utilities, ROE Applicable To Transmission Formula Rates In The MISO Region, Approved

10.32%

10.32%

10.32%

Public Utilities, ROE Applicable To Transmission Formula Rates In The MISO Region, with RTO Adder, Approved

10.82%

Public Utilities, ROE Basis Point Adder, Approved

50

NSP-Minnesota | Administrative Law Judge | FERC Proceeding, MISO ROE Complaint

Public Utilities, General Disclosures [Line Items]

Public Utilities, ROE Applicable to Transmission Formula Rates in the MISO Region, Recommended by Third Parties

9.70%

Minimum | NSP-Minnesota | Nuclear Project Prudency Investigation

Public Utilities, General Disclosures [Line Items]

Public Utilities, Facility Generating Capacity, In MW | MW

600

Maximum | NSP-Minnesota | Nuclear Project Prudency Investigation

Public Utilities, General Disclosures [Line Items]

Public Utilities, Facility Generating Capacity, In MW | MW

671

Commitments and Contingencies,

Commitments and Contingencies, Fuel Contracts (Details) $ in Millions	12 Months Ended
	Dec. 31, 2017USD ($)
Unrecorded Unconditional Purchase Obligation [Line Items]
Minimum annual tolerance band percentage for future rate recovery or refund of fuel costs (in hundredths)	2.00%
Coal
Fuel Contracts [Abstract]
2,018	$ 6.4
2,019	0.6
2,020	0.6
2,021	0.7
2,022	0.7
Thereafter	0.7
Total	9.7	[1]
Natural Gas Supply
Fuel Contracts [Abstract]
2,018	9.4
2,019	0.4
2,020	0.3
2,021	0.3
2,022	0.2
Thereafter	0
Total	10.6	[1]
Natural Gas Storage and Transportation
Fuel Contracts [Abstract]
2,018	13.3
2,019	12.3
2,020	10.1
2,021	9.5
2,022	8.2
Thereafter	30.5
Total	$ 83.9	[1]
Minimum
Unrecorded Unconditional Purchase Obligation [Line Items]
Fuel Contract Expiration Date	2,018
Maximum
Unrecorded Unconditional Purchase Obligation [Line Items]
Fuel Contract Expiration Date	2,029
[1]	Excludes additional amounts allocated to NSP-Wisconsin through intercompany charges.

Commitments and Contingencies73

Commitments and Contingencies, Leases (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Operating Leases [Abstract]
Total expenses under operating lease obligations	$ 1.2	$ 1.2	$ 1.1
Office Space and Other Equipment
Operating Leases, Future Minimum Payments Due [Abstract]
2,018	0.9
2,019	0.9
2,020	0.9
2,021	0.8
2,022	0.8
Thereafter	4.6
Total	$ 8.9

Commitments and Contingencies74

Commitments and Contingencies, Variable Interest Entities (Details) - Low-Income Housing Limited Partnerships - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Amount Reflected in Consolidated Balance Sheets [Abstract]
Current assets	$ 426	$ 375
Property, plant and equipment, net	1,882	2,025
Other noncurrent assets	137	125
Total assets	2,445	2,525
Current liabilities	1,214	1,269
Mortgages and other long-term debt payable	486	486
Other noncurrent liabilities	56	54
Total liabilities	$ 1,756	$ 1,809

Commitments and Contingencies75

Commitments and Contingencies, Joint Operating System (Details) $ in Millions	12 Months Ended
	Dec. 31, 2017USD ($)PlantReactorCounterparty
Joint Operating System [Abstract]
Number of companies covered by FERC approved Interchange Agreement | Counterparty	2
NSP-Minnesota | Nuclear Insurance
Joint Operating System [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	$ 127
Number of owned and licensed reactors | Reactor	3
Maximum funding requirement per reactor for any one year	$ 19
Insurance coverage limits for NSP-Minnesota's nuclear plant sites	$ 2,300
Number of nuclear plant sites operated by NSP-Minnesota | Plant	2
Maximum assessments for business interruption insurance each calendar year	$ 19
Maximum assessment for property damage insurance NSP-Minnesota is subject to each calendar year	41
Maximum | NSP-Minnesota | Nuclear Insurance
Joint Operating System [Abstract]
Maximum possible loss contingency	$ 13,400

Commitments and Contingencies76

Commitments and Contingencies, Guarantees (Details) - Payment or Performance Guarantee - Customer Loans for Farm Rewiring Program	12 Months Ended
	Dec. 31, 2017USD ($)
Guarantee [Abstract]
Assets held as collateral	$ 0
Guarantees issued and outstanding	1,000,000	[1],[2]
Current exposure under these guarantees	$ 0	[1],[2]
Guarantee Expiration Date (year)	2,020	[1],[2]
Guarantee Obligations Claims made	$ 0
[1]	(a) The term of this guarantee expires in 2020, which is the final scheduled repayment date for the loans. As of Dec. 31, 2017, no claims had been made by the lender.
[2]	(b) The debtor becomes the subject of bankruptcy or other insolvency proceedings.

Commitments and Contingencies77

Commitments and Contingencies, Environmental Contingencies - Site Contingencies (Details) $ in Millions	12 Months Ended
	Dec. 31, 2017USD ($)Site	Dec. 31, 2016USD ($)
Ashland MGP Site
Manufactured Gas Plant (MGP) Site [Abstract]
Number of Properties Not Owned Included in Superfund Site | Site	2
Current Cost Estimate for Site Remediation	$ 168
Estimated Amount Spent on Cleanup	138
Accrual for Environmental Loss Contingencies, Gross	$ 30	$ 64
Approved Amortization Period for Recovery of Remediation Costs in Natural Gas Rates	10 years
Carrying Cost Percentage to Be Applied to Unamortized Regulatory Asset	3.00%
Other MGP Sites
Manufactured Gas Plant (MGP) Site [Abstract]
Number of Identified MGP sites Under Current Investigation and/or Remediation | Site	1
Liability for Estimated Cost of Remediating Site	$ 0.1	$ 0
PSCW Proceeding - Electric and Gas Rate Case 2016 - Gas Rates 2016 | Ashland MGP Site
Manufactured Gas Plant (MGP) Site [Abstract]
Public Utilities, Approved Annual Recovery, Collected Through Base Rates	12
PSCW Proceeding - Gas Rate Case 2017 - Gas Rates 2017 | Ashland MGP Site
Manufactured Gas Plant (MGP) Site [Abstract]
Public Utilities, Approved Annual Recovery Collected Through Base Rates	$ 18

Commitments and Contingencies C

Commitments and Contingencies Commitments and Contingencies, Environmental Contingencies - Unrecorded Unconditional Purchase Obligation (Details) $ in Millions	Dec. 31, 2017USD ($)Plant	Dec. 31, 2015Period
Federal Clean Water Act Section 316(b)
Environmental Requirements [Abstract]
Minimum Number of Plants Which Could Be Required to Make Improvements to Reduce Entrainment | Plant	2
National Ambient Air Quality Standards for Ozone
Environmental Requirements [Abstract]
Number of Hours Measured for Standard | Period		8
Former Level of Air Quality Concentrations (in parts per billion)		75
Revised Level of Air Quality Concentrations (in parts per billion)		70
Capital Addition Purchase Commitments [Member] | Federal Clean Water Act Section 316(b)
Environmental Requirements [Abstract]
Liability for Estimated Cost to Comply with Entrainment Regulation | $	$ 4

Commitments and Contingencies79

Commitments and Contingencies, Asset Retirement Obligations (Details) - USD ($)		12 Months Ended
		Dec. 31, 2017		Dec. 31, 2016
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	[2]	$ 11,392,000	[1],[3],[4]	$ 9,687,000
Asset Retirement Obligation, Liabilities Incurred	[1],[4]	949,000		0
Asset Retirement Obligation, Liabilities Settled	[2]	0		(29,000)
Accretion		421,000	[1],[4]	342,000	[2]
Cash Flow Revisions		1,661,000	[1],[4]	1,392,000	[2]
Ending balance	[1],[4]	14,423,000		11,392,000	[2],[3]
Electric Plant Steam Production Asbestos
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance		2,194,000	[3]	2,145,000
Asset Retirement Obligation, Liabilities Incurred	[5]	949,000
Asset Retirement Obligation, Liabilities Settled				0
Accretion		50,000		49,000
Cash Flow Revisions		0		0
Ending balance		3,193,000	[4]	2,194,000	[3]
Electric Plant Steam Production Ash Containment
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance		452,000	[3]	617,000
Asset Retirement Obligation, Liabilities Incurred		0
Asset Retirement Obligation, Liabilities Settled				0
Accretion		15,000		18,000
Cash Flow Revisions		0		(183,000)
Ending balance		467,000	[4]	452,000	[3]
Electric Plant Electric Distribution
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance		32,000	[3]	72,000
Asset Retirement Obligation, Liabilities Incurred		0
Asset Retirement Obligation, Liabilities Settled				0
Accretion		3,000		3,000
Cash Flow Revisions		0		(43,000)
Ending balance		35,000	[4]	32,000	[3]
Electric Plant Other
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance		376,000	[3]	391,000
Asset Retirement Obligation, Liabilities Incurred		0
Asset Retirement Obligation, Liabilities Settled				(29,000)
Accretion		12,000		14,000
Cash Flow Revisions		0		0
Ending balance		388,000	[4]	376,000	[3]
Natural Gas Plant Gas Distribution
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance		8,293,000	[3]	6,367,000
Asset Retirement Obligation, Liabilities Incurred		0
Asset Retirement Obligation, Liabilities Settled				0
Accretion		339,000		256,000
Cash Flow Revisions		1,661,000	[6]	1,670,000
Ending balance		10,293,000	[4]	8,293,000	[3]
Common and Other Property Common Miscellaneous
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance		45,000	[3]	95,000
Asset Retirement Obligation, Liabilities Incurred		0
Asset Retirement Obligation, Liabilities Settled				0
Accretion		2,000		2,000
Cash Flow Revisions		0		(52,000)
Ending balance		$ 47,000	[4]	$ 45,000	[3]
[1]	Included in other long-term liabilities balance in the consolidated balance sheet.
[2]	Included in other long-term liabilities balance in the consolidated balance sheet.
[3]	There were no ARO liabilities recognized during the year ended Dec. 31, 2016.
[4]	There were no ARO liabilities settled during the year ended Dec. 31, 2017.
[5]	The liability recognized relates to asbestos at the French Island plant.
[6]	Changes in the gas distribution ARO are mainly related to increased labor costs.

Commitments and Contingencies80

Commitments and Contingencies Commitments and Contingencies, Removal Costs (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Plant Removal Costs
Regulatory Liabilities [Line Items]
Regulatory Liabilities	$ 146	$ 140

Commitments and Contingencies81

Commitments and Contingencies, Legal Contingencies (Details) - Gas Trading Litigation	1 Months Ended
	Nov. 30, 2017	Dec. 31, 2017	Dec. 31, 2009
Loss Contingencies [Line Items]
Loss Contingency, Pending Claims, Number		6	13
Loss Contingency, Subset of Cases within Multi-District Litigation, Number		2
NSP-Wisconsin
Loss Contingencies [Line Items]
Loss Contingency, Pending Claims, Number			2
Summary Judgment Granted Against Plaintiff [Member]
Loss Contingencies [Line Items]
Loss Contingency, Number of Plaintiffs	2
Remaining in the Litigation [Member]
Loss Contingencies [Line Items]
Loss Contingency, Number of Plaintiffs	3

Regulatory Assets and Liabili82

Regulatory Assets and Liabilities, Regulatory Assets (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2017		Dec. 31, 2016
Regulatory Assets [Line Items]
Regulatory Asset, Current		$ 23,113		$ 18,162
Regulatory Asset, Noncurrent		$ 282,217		286,188
Environmental Remediation Costs
Regulatory Assets [Line Items]
Regulatory asset, remaining amortization period		Various
Regulatory Asset, Current		$ 16,006		10,669
Regulatory Asset, Noncurrent		$ 136,146		148,880
Pension and Retiree Medical Obligations
Regulatory Assets [Line Items]
Regulatory asset, remaining amortization period		Various
Regulatory Asset, Current	[1]	$ 5,674		5,989
Regulatory Asset, Noncurrent	[1]	$ 87,505		93,160
Excess deferred taxes - TCJA
Regulatory Assets [Line Items]
Regulatory asset, remaining amortization period		Various
Regulatory Asset, Current		$ 0		0
Regulatory Asset, Noncurrent		$ 22,605		0
State Commission Adjustments
Regulatory Assets [Line Items]
Regulatory asset, remaining amortization period		Plant lives
Regulatory Asset, Current		$ 716		703
Regulatory Asset, Noncurrent		$ 15,932		14,008
Recoverable Deferred Taxes on AFUDC Recorded in Plant
Regulatory Assets [Line Items]
Regulatory asset, remaining amortization period		Plant lives
Regulatory Asset, Current		$ 0	[2]	0
Regulatory Asset, Noncurrent		14,286	[2]	22,345
Revaluation of Regulatory Assets for New Federal Tax Rate [Member]
Regulatory Assets [Line Items]
Regulatory Assets		$ 11,300
Losses on Reacquired Debt
Regulatory Assets [Line Items]
Regulatory asset, remaining amortization period		Term of related debt
Regulatory Asset, Current		$ 655		801
Regulatory Asset, Noncurrent		$ 2,678		3,333
Other Regulatory Assets
Regulatory Assets [Line Items]
Regulatory asset, remaining amortization period		Various
Regulatory Asset, Current		$ 62		0
Regulatory Asset, Noncurrent		$ 3,065		$ 4,462
[1]	(a) Includes the non-qualified pension plan.
[2]	(b) Includes a write-down of $11.3 million as a result of the revaluation of deferred tax gross up at the new federal tax rate at Dec. 31, 2017.

Regulatory Assets and Liabili83

Regulatory Assets and Liabilities, Regulatory Liabilities (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017		Dec. 31, 2016
Regulatory Liabilities [Line Items]
Regulatory Liability, Current	$ 20,712		$ 17,428
Regulatory Liability, Noncurrent	$ 386,807		148,189
Excess deferred taxes - TCJA
Regulatory Liabilities [Line Items]
Regulatory liability, remaining amortization period	Various
Regulatory Liability, Current	$ 0	[1]	0
Regulatory Liability, Noncurrent	236,589	[1]	0
Revaluation of Non-plant ADIT	$ 41,000
Plant Removal Costs
Regulatory Liabilities [Line Items]
Regulatory liability, remaining amortization period	Plant lives
Regulatory Liability, Current	$ 0		0
Regulatory Liability, Noncurrent	$ 146,370		139,735
Deferred Electric Production And Natural Gas Costs
Regulatory Liabilities [Line Items]
Regulatory liability, remaining amortization period	Less than one year
Regulatory Liability, Current	$ 13,950		11,377
Regulatory Liability, Noncurrent	$ 0		0
DOE Settlement
Regulatory Liabilities [Line Items]
Regulatory liability, remaining amortization period	Less than one year
Regulatory Liability, Current	$ 5,261		4,822
Regulatory Liability, Noncurrent	$ 0		0
Other Regulatory Liabilities
Regulatory Liabilities [Line Items]
Regulatory liability, remaining amortization period	Various
Regulatory Liability, Current	$ 1,501		1,229
Regulatory Liability, Noncurrent	$ 3,848		$ 8,454
[1]	(a) Primarily relates to the revaluation of recoverable/regulated plant ADIT and $41.0 million revaluation impact of non-plant ADIT at Dec. 31, 2017.

Other Comprehensive Income (Det

Other Comprehensive Income (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Accumulated Other Comprehensive Income (Loss) [Line Items]
Accumulated other comprehensive loss at beginning of period		$ 811,850
Accumulated other comprehensive loss at end of period		876,589	$ 811,850
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Adoption of ASU No. 2018-02		0
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Total, pre-tax		(123,588)	(112,037)	$ (118,874)
Income tax expense (benefit)		44,172	42,902	44,238
Gains and Losses on Cash Flow Hedges
Accumulated Other Comprehensive Income (Loss) [Line Items]
Accumulated other comprehensive loss at beginning of period		(133)	(209)
Accumulated other comprehensive loss at end of period		(69)	(133)	$ (209)
AOCI Attributable to Parent, Net of Tax [Roll Forward]
(Gains) losses reclassified from net accumulated other comprehensive loss		76	76
Net current period other comprehensive income (loss)		76	76
Adoption of ASU No. 2018-02	[1]	(12)
Gains and Losses on Cash Flow Hedges | Amounts Reclassified from Accumulated Other Comprehensive Loss
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Total, pre-tax		126	127
Income tax expense (benefit)		(50)	(51)
Total, net of tax		76	76
Gains and Losses on Cash Flow Hedges | Interest Rate Derivatives | Amounts Reclassified from Accumulated Other Comprehensive Loss
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Interest charges	[2]	$ 126	$ 127
[1]	In 2017, NSP-Wisconsin implemented ASU No. 2018-02 related to the TCJA, which resulted in reclassification of certain credit balances within net accumulated other comprehensive loss to retained earnings. For further information, see Note 2.
[2]	Included in interest charges.

Segments and Related Informat85

Segments and Related Information (Details) - USD ($) $ in Thousands		3 Months Ended								12 Months Ended
		Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Segment Reporting Information [Line Items]
Intercompany Revenue										$ 177,000	$ 170,000	$ 163,000
Operating revenues		$ 262,983	$ 247,511	$ 230,026	$ 264,931	$ 237,066	$ 246,144	$ 219,173	$ 254,850	1,005,451	957,233	956,541
Depreciation and amortization										111,216	98,294	91,245
Total interest charges and financing costs										32,180	32,629	29,221
Income tax expense (benefit)										44,172	42,902	44,238
Net income (loss)		$ 20,431	$ 22,325	$ 14,241	$ 22,419	$ 14,658	$ 24,221	$ 12,625	$ 17,631	79,416	69,135	74,636
Regulated Electric
Segment Reporting Information [Line Items]
Operating revenues										882,388	850,343	835,417
Depreciation and amortization										88,946	81,299	77,036
Total interest charges and financing costs										29,396	29,749	26,494
Income tax expense (benefit)										38,866	40,547	40,654
Net income (loss)										70,876	65,002	69,398
Regulated Natural Gas
Segment Reporting Information [Line Items]
Operating revenues										122,640	106,644	120,645
Depreciation and amortization										22,070	16,794	14,034
Total interest charges and financing costs										2,761	2,855	2,637
Income tax expense (benefit)										4,040	2,445	2,501
Net income (loss)										7,832	4,503	4,862
All Other
Segment Reporting Information [Line Items]
Operating revenues										1,207	1,130	1,396
Depreciation and amortization										200	201	175
Total interest charges and financing costs										23	25	90
Income tax expense (benefit)										1,266	(90)	1,083
Net income (loss)										708	(370)	376
Operating Segments
Segment Reporting Information [Line Items]
Operating revenues	[1]									1,005,451	957,233	956,541
Operating Segments | Regulated Electric
Segment Reporting Information [Line Items]
Operating revenues	[1]									881,891	849,946	834,998
Operating Segments | Regulated Natural Gas
Segment Reporting Information [Line Items]
Operating revenues	[1]									122,353	106,157	120,147
Operating Segments | All Other
Segment Reporting Information [Line Items]
Operating revenues	[1]									1,207	1,130	1,396
Intersegment Eliminations
Segment Reporting Information [Line Items]
Operating revenues										(784)	(884)	(917)
Depreciation and amortization										0	0	0
Total interest charges and financing costs										0	0	0
Income tax expense (benefit)										0	0	0
Net income (loss)										0	0	0
Intersegment Eliminations | Regulated Electric
Segment Reporting Information [Line Items]
Operating revenues										497	397	419
Intersegment Eliminations | Regulated Natural Gas
Segment Reporting Information [Line Items]
Operating revenues										287	487	498
Intersegment Eliminations | All Other
Segment Reporting Information [Line Items]
Operating revenues										$ 0	$ 0	$ 0
[1]	Operating revenues include $177 million, $170 million and $163 million of intercompany revenue for the years ended Dec. 31, 2017, 2016 and 2015 respectively. See Note 15 for further discussion of related party transactions by operating segment.

Related Party Transactions (Det

Related Party Transactions (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Operating revenues
Electric	$ 177,234	$ 170,483	$ 163,255
Operating expenses
Purchased power	421,609	413,615	419,028
Transmission expense	68,613	61,920	54,070
Natural gas purchased for resale	47	41	45
Other operating expenses - paid to Xcel Energy Services Inc.	92,715	106,454	93,890
Interest expense	7	4	$ 2
Accounts Receivable and Payable with Affiliates [Abstract]
Accounts receivable	3,391	333
Accounts payable	29,628	29,037
NSP-Minnesota
Accounts Receivable and Payable with Affiliates [Abstract]
Accounts receivable	0	0
Accounts payable	17,825	18,567
PSCo
Accounts Receivable and Payable with Affiliates [Abstract]
Accounts receivable	0	0
Accounts payable	61	974
SPS
Accounts Receivable and Payable with Affiliates [Abstract]
Accounts receivable	0	333
Accounts payable	7	0
Other subsidiaries of Xcel Energy Inc.
Accounts Receivable and Payable with Affiliates [Abstract]
Accounts receivable	3,391	0
Accounts payable	$ 11,735	$ 9,496

Summarized Quarterly Financia87

Summarized Quarterly Financial Data (Unaudited) (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Quarterly Financial Information Disclosure [Abstract]
Operating revenues	$ 262,983	$ 247,511	$ 230,026	$ 264,931	$ 237,066	$ 246,144	$ 219,173	$ 254,850	$ 1,005,451	$ 957,233	$ 956,541
Operating income	37,994	38,392	29,067	42,775	30,360	46,342	27,778	35,448	148,228	139,928	139,959
Net income	$ 20,431	$ 22,325	$ 14,241	$ 22,419	$ 14,658	$ 24,221	$ 12,625	$ 17,631	$ 79,416	$ 69,135	$ 74,636

Schedule II, Valuation and Qu88

Schedule II, Valuation and Qualifying Accounts (Details) - Allowance for Bad Debts - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Movement in Valuation Allowances and Reserves [Roll Forward]
Balance at Jan. 1		$ 4,865	$ 5,128	$ 5,821
Charged to costs and expenses		4,105	3,730	3,947
Charged to other accounts	[1]	952	1,008	1,161
Deductions from reserves	[2]	5,049	5,001	5,801
Balance at Dec. 31		$ 4,873	$ 4,865	$ 5,128
[1]	Recovery of amounts previously written off.
[2]	Deductions relate primarily to bad debt write-offs.