Northern States Power 10-K 22 Feb 19 2018 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2018	Feb. 22, 2019	Jun. 29, 2018
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
Entity Emerging Growth Company	false
Entity Small Business	false
Entity Shell Company	false
Document Type	10-K
Document Period End Date	Dec. 31, 2018
Document Fiscal Year Focus	2,018
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 Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Revenues	$ 1,021.5	$ 1,005.5	$ 957.2
Operating expenses
Purchased power, affiliates	410.9	421.6	413.6
Cost of natural gas sold and transported	69.1	62.3	54.4
Operating and maintenance expenses	201.9	201.2	192
Conservation program expenses	12.3	12.6	12.7
Depreciation and amortization	126.1	111.2	98.3
Taxes (other than income taxes)	28.7	27.8	27.8
Total operating expenses	862.1	852.9	814.4
Operating income	159.4	152.6	142.8
Interest charges and financing costs
Interest charges — includes other financing costs of $1.8, $1,9, and $1.9, respectively	39.3	35	34.4
Public Utilities, Allowance For Funds Used During Construction, Capitalized Cost Of Debt	(4.1)	(2.8)	(1.8)
Total interest charges and financing costs	35.2	32.2	32.6
Other Income and Expenses [Abstract]
Other income, net	(3.1)	(3.5)	(2.5)
Allowance for funds used during construction — equity	9.2	6.7	4.3
Income before income taxes	130.3	123.6	112
Income taxes	32.3	44.2	42.9
Net income	98	79.4	69.1
Electricity, US Regulated [Member]
Revenues	720.7	704.7	679.5
Affiliate Revenue	157.9	177.2	170.4
Operating expenses
Cost of goods and services sold	13.1	16.2	15.6
Natural Gas, US Regulated [Member]
Revenues	141.6	122.4	106.2
Product and Service, Other [Member]
Revenues	$ 1.3	$ 1.2	$ 1.1

CONSOLIDATED STATEMENTS OF IN_2

CONSOLIDATED STATEMENTS OF INCOME (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
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 Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Comprehensive income:
Net income	$ 98	$ 79.4	$ 69.1
Derivative instruments:
Reclassification of losses to net income, net of tax of $0 and $0, and $0, respectively.	0.1	0	0.1
Other comprehensive income	0.1	0	0.1
Comprehensive income	$ 98.1	$ 79.4	$ 69.2

CONSOLIDATED STATEMENTS OF CO_2

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	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 Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Operating activities
Net income	$ 98	$ 79.4	$ 69.1
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	127.6	112.7	99.8
Deferred income taxes	23.3	45.6	37.4
Allowance for equity funds used during construction	(9.2)	(6.7)	(4.3)
Provision for bad debts	4.2	4.1	3.7
Net derivative losses	(0.1)	0.1	0.2
Changes in operating assets and liabilities:
Accounts receivable	(4.6)	(9.9)	(1.4)
Accrued unbilled revenues	3.8	(6.4)	(5.9)
Inventories	(7.5)	0.6	3.3
Other current assets	2.1	0.9	(1.2)
Accounts payable	(9.1)	9	10.6
Net regulatory assets and liabilities	(19.8)	(31.2)	(18.6)
Other current liabilities	(13.1)	(2.2)	14
Pension and other employee benefit obligations	(14.6)	(8.6)	(6.2)
Increase (Decrease) in Other Operating Assets and Liabilities, Net	2.7	(7.6)	0.2
Net cash provided by operating activities	183.7	179.8	200.7
Investing activities
Utility capital/construction expenditures	(226.6)	(212.1)	(200.1)
Other, net	0.2	0	1.2
Net cash used in investing activities	(226.4)	(212.1)	(198.9)
Financing activities
Proceeds from (repayments of) short-term borrowings, net	40	(49)	50
Proceeds from issuance of long-term debt	196.6	97.5	0
Repayments of long-term debt	(151.1)	(0.1)	(0.1)
Capital contributions from parent	49.2	48	1.9
Dividends paid to parent	(91.1)	(64)	(53.1)
Other, net	(0.1)	(0.2)	(0.1)
Net cash provided by (used in) financing activities	43.5	32.2	(1.4)
Net change in cash and cash equivalents	0.8	(0.1)	0.4
Cash and cash equivalents at beginning of period	1.4	1.5	1.1
Cash and cash equivalents at end of period	2.2	1.4	1.5
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	(32.9)	(30.9)	(30.9)
Cash (paid) received for income taxes, net	(20.6)	(5)	5.9
Supplemental disclosure of non-cash investing transactions:
Accrued property, plant and equipment additions	32	31	22.7
Inventory transfers to plant, property and equipment	8.2	5.5	8.3
Allowance for Funds Used During Construction, Investing Activities	$ 9.2	$ 6.7	$ 4.3

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Current assets
Cash and cash equivalents	$ 2.2	$ 1.4
Accounts receivable, net	75.1	63.2
Accrued unbilled revenues	56.2	60
Other receivables	6.8	15.1
Public Utilities, Inventory	17.1	17.8
Regulatory assets	22.6	23.1
Prepaid taxes	30.2	23.6
Prepayments	3.3	3.5
Total current assets	213.5	207.7
Property, Plant and Equipment, Net	2,241.6	2,088.7
Other assets
Regulatory assets	285.5	282.2
Other investments	2.7	2.9
Other	0.2	0.2
Total other assets	288.4	285.3
Total assets	2,743.5	2,581.7
Current liabilities
Current portion of long-term debt	0	151.1
Short-term debt	51	11
Notes payable to affiliates	0.6	0.5
Accounts payable	56.8	58.3
Accounts payable to affiliates	20	29.6
Dividends payable to parent	17.4	15.5
Regulatory liabilities	20.9	20.7
Environmental liabilities	10.9	10.5
Accrued interest	8.8	8
Other	17.8	34.5
Total current liabilities	204.2	339.7
Deferred credits and other liabilities
Deferred income taxes	280.7	256.7
Deferred investment tax credits	7	7.5
Regulatory liabilities	400.1	386.8
Environmental liabilities	18	19.2
Customer advances	16.8	16.3
Pension and employee benefit obligations	44.5	50
Other	22.3	18.8
Total deferred credits and other liabilities	789.4	755.3
Commitments and contingencies
Capitalization
Long-term debt	807.5	610.1
Common stock — 1,000,000 shares authorized of $100 par value; 933,000 shares outstanding at Dec. 31, 2018 and 2017, respectively	93.3	93.3
Additional paid in capital	510.1	449.4
Retained earnings	339	334
Accumulated other comprehensive loss	0	(0.1)
Total common stockholder’s equity	942.4	876.6
Total liabilities and equity	$ 2,743.5	$ 2,581.7

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares	Dec. 31, 2018	Dec. 31, 2017
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 Millions	Total	Common stock	Additional Paid In Capital	Retained Earnings	Accumulated Other Comprehensive Loss
Beginning Balance at Dec. 31, 2015	$ 790.4	$ 93.3	$ 394.6	$ 302.7	$ (0.2)
Balance (in shares) at Dec. 31, 2015		933,000
Comprehensive income:
Net income	69.1			69.1
Other comprehensive income	0.1				0.1
Common dividends declared to parent	(48.5)			(48.5)
Contribution of capital by parent	0.8		0.8
Ending Balance at Dec. 31, 2016	811.9	$ 93.3	395.4	323.3	(0.1)
Balance (in shares) at Dec. 31, 2016		933,000
Comprehensive income:
Net income	79.4			79.4
Other comprehensive income	0				0
Common dividends declared to parent	(68.7)			(68.7)
Contribution of capital by parent	54		54
Ending Balance at Dec. 31, 2017	$ 876.6	$ 93.3	449.4	334	(0.1)
Balance (in shares) at Dec. 31, 2017	933,000	933,000
Comprehensive income:
Net income	$ 98			98
Other comprehensive income	0.1				0.1
Common dividends declared to parent	(93)			(93)
Contribution of capital by parent	60.7		60.7
Ending Balance at Dec. 31, 2018	$ 942.4	$ 93.3	$ 510.1	$ 339	$ 0
Balance (in shares) at Dec. 31, 2018	933,000	933,000

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2018
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	Summary of Significant Accounting Policies General — 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 include its wholly-owned subsidiaries and VIEs 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 3 for further information. 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. NSP-Wisconsin has evaluated the impact of events occurring after Dec. 31, 2018 up to the date of issuance of these consolidated financial statements. These statements contain all necessary adjustments and disclosures resulting from that evaluation. Use of Estimates — NSP-Wisconsin uses estimates based on the best information available in recording transactions and balances resulting from business operations. Estimates are used on items such as plant depreciable lives or potential disallowances, AROs, certain regulatory assets and liabilities, tax provisions, uncollectible amounts, environmental costs, unbilled revenues, jurisdictional fuel and energy cost allocations and actuarially determined benefit costs. Recorded estimates are revised when better information becomes available or when actual amounts can be determined. Those revisions can affect operating results. Regulatory Accounting — NSP-Wisconsin accounts for income and expense items in accordance with accounting guidance for regulated operations. Under this guidance: • Certain costs, which would otherwise be charged to expense or other comprehensive income, are deferred as regulatory assets based on the expected ability to recover the costs in future rates; and • Certain credits, which would otherwise be reflected as income or other comprehensive income, are deferred as regulatory liabilities based on the expectation the amounts will be returned to customers in future rates, or because the amounts were collected in rates prior to the costs being incurred. Estimates of recovering deferred costs and returning deferred credits are based on specific ratemaking decisions or precedent for each item. Regulatory assets and liabilities are amortized consistent with the treatment in the rate setting process. If changes in the regulatory environment occur, NSP-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 results of operations, financial condition or cash flows. See Note 4 for further information. Income Taxes — NSP-Wisconsin accounts for income taxes using the asset and liability method, which require 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. Reversal of certain temporary differences are accounted for as current income tax expense due to the effects of past regulatory practices when deferred taxes were not required to be recorded due to the use of flow through accounting for ratemaking purposes. Tax credits are recorded when earned unless there is a requirement to defer the benefit and amortize it over the book depreciable lives of the related property. The requirement to defer and amortize tax credits only applies to federal ITCs related to public utility property. Utility rate regulation also has resulted in the recognition of regulatory assets and liabilities related to income taxes. Deferred tax assets are reduced by a valuation allowance if it is more likely than not that some portion or all of the deferred tax asset will not be realized. NSP-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 in the consolidated statements of income. Xcel Energy Inc. and its subsidiaries, including NSP-Wisconsin, file consolidated federal income tax returns as well as consolidated or separate state income tax returns. Federal income taxes paid by Xcel Energy Inc. are allocated to Xcel Energy Inc.’s subsidiaries based on separate company computations. A similar allocation is made for state income taxes paid by Xcel Energy Inc. in connection with consolidated state filings. Xcel Energy Inc. also allocates its own income tax benefits to its direct subsidiaries. See Note 7 for further information. Property, Plant and Equipment and Depreciation — Property, plant and equipment is stated at original cost. The cost of plant includes direct labor and materials, contracted work, overhead costs and AFUDC. The cost of plant retired is charged to accumulated depreciation and amortization. Amounts recovered in rates for future removal costs are recorded as regulatory liabilities. Significant additions or improvements extending asset lives are capitalized, while repairs and maintenance costs are charged to expense as incurred. Maintenance and replacement of items determined to be less than a unit of property are charged to operating expenses as incurred. Planned maintenance activities are charged to operating expense unless the cost represents the acquisition of an additional unit of property or the replacement of an existing unit of property. Property, plant and equipment is tested for impairment when it is determined that the carrying value of the assets may not be recoverable. A loss is recognized in the current period if it becomes probable that part of a cost of a plant under construction or recently completed plant will be disallowed for recovery from customers and a reasonable estimate of the disallowance can be made. For investments in property, plant and equipment that are abandoned and not expected to go into service, incurred costs and related deferred tax amounts are compared to the discounted estimated future rate recovery, and a loss is recognized, if necessary. NSP-Wisconsin records depreciation expense 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 3.5% in 2018, 3.4% in 2017 and 3.3% in 2016. See Note 3 for further information. 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 10 for further information. 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 requires management to make various assumptions and estimates. Certain unrecognized actuarial gains and losses and unrecognized prior service costs or credits are deferred as regulatory assets and liabilities, rather than recorded as other comprehensive income, based on regulatory recovery mechanisms. See Note 9 for further information. Environmental Costs — Environmental costs are recorded when it is probable NSP-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 are regularly adjusted as estimates are revised and remediation proceeds. If other participating potentially responsible parties exist and acknowledge their potential involvement with a site, costs are estimated and recorded only for NSP-Wisconsin’s expected share of the cost. Future costs of restoring sites are treated as a capitalized cost of plant retirement. The depreciation expense levels recoverable in rates include a provision for removal expenses. Removal costs recovered in rates before the related costs are incurred are classified as a regulatory liability. See Note 10 for further information. Revenue From Contracts With Customers — Performance obligations related to the sale of energy are satisfied as energy is delivered to customers. NSP-Wisconsin recognizes revenue that corresponds to the price of the energy delivered to the customer. The measurement of energy sales to customers is generally based on the reading of their meters, which occurs 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 does not recognize a separate financing component of its collections from customers as contract terms are short-term in nature . NSP-Wisconsin presents its revenues net of any excise or sales taxes or fees. NSP-Wisconsin has various rate-adjustment mechanisms that provide for the recovery of natural gas, electric fuel and purchased energy costs. Cost-adjustment tariffs may increase or decrease the level of revenue collected from customers and are revised periodically for differences between the total amount collected under the clauses and the costs incurred. When applicable, fuel cost over-recoveries (the excess of fuel revenue billed to customers over fuel costs incurred) are deferred as regulatory liabilities and under-recoveries (the excess of fuel costs incurred over fuel revenues billed to customers) are deferred as regulatory assets. 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 2% annual tolerance band, for future rate recovery or refund, subject to PSCW approval. Cash and Cash Equivalents — NSP-Wisconsin considers investments in instruments with a remaining maturity of three months or less at the time of purchase, to be cash equivalents. Accounts Receivable and Allowance for Bad Debts — Accounts receivable are stated at the actual billed amount net of an allowance for bad debts. NSP-Wisconsin establishes an allowance for uncollectible receivables based on a policy that reflects its expected exposure to the credit risk of customers. As of Dec. 31, 2018 and 2017, the allowance for bad debts was $5.6 million and $4.9 million , respectively. Inventory — Inventory is recorded at average cost. As of Dec. 31, 2018, materials and supplies, fuel and natural gas inventory were $6.7 million , $3.8 million and $6.6 million , respectively. As of Dec. 31, 2017, materials and supplies, fuel and natural gas inventory were $6.9 million , $3.9 million and $7.0 million , respectively. 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 to establish fair value. For commodity derivatives, the most observable inputs available are generally used to determine the fair value of each contract. In the absence of a quoted price, NSP-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 8 and 9 for further information. 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. Any derivative instruments not qualifying for the normal purchases and normal sales exception are recorded on the consolidated balance sheets at fair value as derivative instruments. Classification of changes in fair value for those derivative instruments is dependent on the designation of a qualifying hedging relationship. Changes in fair value of derivative instruments not designated in a qualifying hedging relationship are reflected in current earnings or as a regulatory asset or liability. Classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms. 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. Normal Purchases and Normal Sales — NSP-Wisconsin enters into contracts for purchases and sales of commodities for use in its operations. At inception, contracts are evaluated to determine whether a derivative exists and/or whether an instrument may be exempted from derivative accounting if designated as a normal purchase or normal sale. See Note 8 for further information. Other Utility Items AFUDC — AFUDC represents the cost of capital used to finance utility construction activity. AFUDC is computed by applying a composite financing rate to qualified CWIP. The amount of AFUDC capitalized as a utility construction cost is credited to other nonoperating income (for equity capital) and interest charges (for debt capital). AFUDC amounts capitalized are included in NSP-Wisconsin’s rate base for establishing utility service rates. Alternative Revenue — Certain rate rider mechanisms qualify as alternative revenue programs under GAAP. These mechanisms arise from costs imposed upon the utility by action of a regulator or legislative body related to an environmental, public safety or other mandate. When certain criteria are met, such as collection within 24 months , revenue is recognized equal to the revenue requirement, which may include return on rate base items and incentives. The mechanisms are revised periodically for differences between the total amount collected and the revenue recognized, which may increase or decrease the level of revenue collected from customers. Alternative revenues arising from these programs are presented on a gross basis and disclosed separately from revenue from contracts with customers in the period earned. See Note 6 for further information. 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% 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. Emission Allowances — Emission allowances are recorded at cost plus broker commission fees. The inventory accounting model is utilized for all emission allowances and sales of these allowances are included in electric revenues. RECs — Cost of RECs that are utilized for compliance purposes is recorded as electric fuel and purchased power expense. Sales of RECs are recorded in electric revenues on a gross basis. The cost of these RECs are recorded in electric fuel and purchased power expense.

Accounting Pronouncements

Accounting Pronouncements	12 Months Ended
	Dec. 31, 2018
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]
Accounting Pronouncements	Accounting Pronouncements Recently Issued Leases — In 2016, the FASB issued Leases, Topic 842 (ASU No. 2016-02) , which requires balance sheet recognition of right-of-use assets and lease liabilities for most leases. Adoption will occur on Jan. 1, 2019 utilizing the package of transition practical expedients provided by the new standard, including carrying forward prior conclusions of whether agreements existing before the adoption date contain leases, and whether existing leases are operating or capital/finance leases. NSP-Wisconsin expects to utilize other expedients offered by the new standard and Leases, Topic 842 (ASU No. 2018-11) , including elections to not recognize short term leases on the consolidated balance sheet for certain classes of assets and to implement the standard on a prospective basis. NSP-Wisconsin’s implementation of the new guidance is substantially complete, and the implementation is not expected to have a significant impact on NSP-Wisconsin’s consolidated financial statements. Recently Adopted Revenue Recognition — In 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. NSP-Wisconsin implemented the guidance on a modified retrospective basis on Jan. 1, 2018. Results for reporting periods beginning after Dec. 31, 2017 are presented in accordance with Topic 606, while prior period results have not been adjusted and continue to be reported in accordance with prior accounting guidance. The implementation did not have a material impact on NSP-Wisconsin’s consolidated financial statements, other than increased disclosures regarding revenues related to contracts with customers. Classification and Measurement of Financial Instruments — In 2016, the FASB issued Recognition and Measurement of Financial Assets and Financial Liabilities, Subtopic 825-10 (ASU No. 2016-01) , which eliminated the available-for-sale classification for marketable equity securities and also replaced the cost method of accounting for non-marketable equity securities with a model for recognizing impairments and observable price changes. NSP-Wisconsin implemented the guidance on Jan. 1, 2018 and the adoption impacts were not material. Presentation of Net Periodic Benefit Cost — In 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 portion of pension cost may be presented as a component of operating income. In addition, only the service cost portion of pension cost is eligible for capitalization. As a result of regulatory accounting treatment, a similar amount of pension cost, including non-service components, will be recognized consistent with historical ratemaking and the impacts of adoption are limited to changes in classification of non-service costs in the consolidated statement of income. NSP-Wisconsin implemented the new guidance on Jan. 1, 2018. As a result, $4.3 million and $3.0 million of pension costs were retrospectively reclassified from operating and maintenance expenses to other expense, net on the consolidated income statement for 2017 and 2016, respectively. NSP-Wisconsin used benefit cost amounts disclosed for prior periods as the basis for retrospective application.

Property Plant and Equipment Pr

Property Plant and Equipment Property Plant and Equipment	12 Months Ended
	Dec. 31, 2018
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment Disclosure	Property, Plant, and Equipment Major classes of property, plant and equipment: (Millions of Dollars) Dec. 31, 2018 Dec. 31, 2017 Property, plant and equipment Electric plant $ 2,895.5 $ 2,602.7 Natural gas plant 345.7 326.7 Common and other property 189.7 181.1 CWIP 55.0 148.8 Total property, plant and equipment 3,485.9 3,259.3 Less accumulated amortization (1,244.3 ) (1,170.6 ) $ 2,241.6 $ 2,088.7 Joint Ownership of Transmission Facilities Jointly owned assets as of Dec. 31, 2018 : (Millions of Dollars) Plant in Accumulated Depreciation CWIP Percent Owned Electric Transmission: La Crosse, Wis. to Madison, Wis. $ 175.4 $ 2.2 $ — 37 % CapX2020 Transmission 168.4 14.5 2.3 81 Total $ 343.8 $ 16.7 $ 2.3 NSP-Wisconsin’s share of operating expenses and construction expenditures are included in the applicable utility accounts. Respective owners are responsible for providing their own financing.

Regulatory Assets and Liabiliti

Regulatory Assets and Liabilities	12 Months Ended
	Dec. 31, 2018
Regulatory Assets and Liabilities Disclosure [Abstract]
Regulatory Assets and Liabilities	Regulatory Assets and Liabilities Regulatory assets and liabilities are created for amounts that regulators may allow to be collected, or may require to be paid back to customers in future electric and natural gas rates. NSP-Wisconsin would be required to recognize the write-off of regulatory assets and liabilities in net income or other comprehensive income if changes in the utility industry no longer allow for the application of regulatory accounting guidance under GAAP. Components of regulatory assets: (Millions of Dollars) See Note(s) Remaining Dec. 31, 2018 Dec. 31, 2017 Regulatory Assets Current Noncurrent Current Noncurrent Environmental remediation costs 1, 10 Various $ 16.0 $ 135.2 $ 16.0 $ 136.1 Pension and retiree medical obligations 9 Various 5.5 85.1 5.7 87.5 Excess deferred taxes - TCJA 7 Various — 25.2 — 22.6 Recoverable deferred taxes on AFUDC recorded in plant Plant lives — 16.9 — 14.3 State commission adjustments Plant lives 0.8 16.8 0.7 15.9 Losses on reacquired debt Term of related debt 0.2 2.4 0.7 2.7 Other Various 0.1 3.9 — 3.1 Total regulatory assets $ 22.6 $ 285.5 $ 23.1 $ 282.2 Components of regulatory liabilities: (Millions of Dollars) See Note(s) Remaining Dec. 31, 2018 Dec. 31, 2017 Regulatory Liabilities Current Noncurrent Current Noncurrent Deferred income tax adjustments and TCJA refunds (a) 7 Various $ 0.2 $ 238.3 $ — $ 236.1 Plant removal costs 1, 10 Plant lives — 157.7 — 146.4 Deferred electric production and natural gas costs Less than one year 13.4 — 13.9 — United States Department of Energy settlement Less than one year 6.2 — 5.3 — Other Various 1.1 4.1 1.5 4.3 Total regulatory liabilities $ 20.9 $ 400.1 $ 20.7 $ 386.8 (a) Includes the revaluation of recoverable/regulated plant ADIT and revaluation impact of non-plant ADIT due to the TCJA.

Borrowings and Other Financing

Borrowings and Other Financing Instruments Borrowings and Other Financing Instruments	12 Months Ended
	Dec. 31, 2018
Debt Disclosure [Abstract]
Borrowings and Other Financing Instruments	Borrowings and Other Financing Instruments Short Term Borrowings Short-Term Debt — 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: Three Months Ended Dec. 31, 2018 Year Ended (Amounts in Millions, Except Interest Rates) 2018 2017 2016 Borrowing limit $ 150 $ 150 $ 150 $ 150 Amount outstanding at period end 51 51 11 60 Average amount outstanding 51 28 52 15 Maximum amount outstanding 103 103 129 64 Weighted average interest rate, computed on a daily basis 2.56 % 2.31 % 1.23 % 0.69 % Weighted average interest rate at period end 2.89 2.89 1.73 0.95 Letters of Credit — NSP-Wisconsin may use letters of credit, typically with terms of one -year, to provide financial guarantees for certain operating obligations. At Dec. 31, 2018 and 2017 , there were no letters of credit outstanding. Credit Facility — 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. Features of the credit facility: Debt-to-Total Capitalization Ratio (a) Amount Facility May Be Increased (millions) Additional Periods For Which a One-Year Extension May Be Requested (b) 2018 2017 48 % 47 % N/A 1 (a) The NSPW financial covenant requires that the debt-to-total capitalization ratio be less than or equal to 65% . (b) All extension requests are subject to majority bank group approval. The credit facility has a cross-default provision that NSP-Wisconsin will be in default on it borrowings under the facility if NSP-Wisconsin or any of its subsidiaries whose total assets exceed 15% of NSP-Wisconsin’s consolidated total assets, default on certain indebtedness in an aggregate principal amount exceeding $75 million . 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. As of Dec. 31, 2018, NSP-Wisconsin was in compliance with all financial covenants. NSP-Wisconsin had the following committed credit facilities available as of Dec. 31, 2018 (in millions): Credit Facility (a) Drawn (b) Available $ 150 $ 51 $ 99 (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 facility outstanding at Dec. 31, 2018 and 2017 . 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, 2018 Dec. 31, 2017 Notes payable to affiliates $ 0.6 $ 0.5 Weighted average interest rate 2.89 % 1.73 % Long-Term Borrowings and Other Financing Instruments Generally, all 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 for refinanced debt are deferred and amortized over the life of new issuance. Long term debt obligations for NSP-Wisconsin as of Dec. 31: (Millions of Dollars) Maturity Range Interest Rate Range 2018 Interest Rate Range 2017 2018 2017 Mortgage bonds 2024-2048 3.3% - 6.38% 3.3% - 6.38% $ 800 $ 750 City of La Crosse resource recovery bond 2021 6.00 % 6.00 % 19 19 Other — 2 Unamortized discount (3 ) (3 ) Unamortized debt issuance cost (9 ) (7 ) Current maturities — (151 ) Total $ 807 $ 610 Maturities of long-term debt: (Millions of Dollars) 2019 $ — 2020 — 2021 19 2022 — 2023 — 2018 financings: Amount Financing Instrument Interest Rate Maturity Date 200 million First mortgage bonds 4.20 % Sept. 1, 2048 2017 financings: Amount Financing Instrument Interest Rate Maturity Date 100 million First mortgage bonds 3.75 % Dec. 1, 2047 Deferred Financing Costs — Deferred financing costs of approximately $9 million and $7 million , net of amortization, are presented as a deduction from the carrying amount of long-term debt at Dec. 31, 2018 and 2017 , 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. Dividends are solely to be paid from retained earnings. NSP-Wisconsin’s state regulatory commission imposes the most restrictive dividend limitations. Requirements and actuals as of Dec. 31, 2018: Equity to Total Capitalization Ratio Required Range Equity to Total Capitalization Ratio Actual Low High 2018 51.5 % N/A 51.8 % Unrestricted Retained Earnings Total Capitalization Limit on Total Capitalization $ 11.5 million $ 1.7 billion N/A (a) NSP-Wisconsin cannot pay annual dividends in excess of approximately $55 million if its average equity-to-total capitalization ratio falls below the commission authorized level.

Revenues

Revenues	12 Months Ended
	Dec. 31, 2018
Revenue from Contract with Customer [Abstract]
Revenues	Revenues Revenue is classified by the type of goods/services rendered and market/customer type. NSP-Wisconsin’s operating revenues (subsequent to adoption of the revised revenue guidance) consists of the following: Year Ended Dec. 31, 2018 (Millions of Dollars) Electric Natural Gas All Other Total Major revenue types Revenue from contracts with customers: Residential $ 255.2 $ 73.0 $ 0.1 $ 328.3 C&I 444.3 61.6 0.1 506.0 Other 6.1 — 1.1 7.2 Total retail 705.6 134.6 1.3 841.5 Interchange 157.9 — — 157.9 Other 3.6 4.6 — 8.2 Total revenue from contracts with customers 867.1 139.2 1.3 1,007.6 Alternative revenue and other 11.5 2.4 — 13.9 Total revenues $ 878.6 $ 141.6 $ 1.3 $ 1,021.5

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2018
Income Tax Disclosure [Abstract]
Income Taxes	Income Taxes Federal Tax Reform — In 2017, the TCJA was signed into law. The key provisions impacting Xcel Energy (which includes NSP-Wisconsin) generally beginning in 2018, include: • Corporate federal tax rate reduction from 35% to 21% ; • 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% of taxable income); • Repeal of the section 199 manufacturing deduction; and • Reduced deductions for meals and entertainment as well as state and local lobbying. Xcel Energy estimated the effects of the TCJA, which have been reflected in the consolidated financial statements. Reductions in deferred tax assets and liabilities due to a decrease in corporate federal tax rates typically result in a net tax benefit. However, the impacts are primarily recognized as regulatory liabilities refundable to utility customers as a result of IRS requirements and past regulatory treatment. Estimated impacts of the new tax law for NSP-Wisconsin in December 2017 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% 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; and, • 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 accounted for the state tax impacts of federal tax reform based on 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. Federal Audit — NSP-Wisconsin is a member of the Xcel Energy affiliated group that files a consolidated federal income tax return. Statute of limitations applicable to Xcel Energy’s consolidated federal income tax returns expire as follows: Tax Year(s) Expiration 2009 - 2014 October 2019 2015 September 2019 2016 September 2020 2017 September 2021 In 2012, the IRS commenced an examination of tax years 2010 and 2011 , including the 2009 carryback claim. In 2017, Xcel Energy and the Office of 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. In the second quarter of 2018, the Joint Committee on Taxation completed its review and took no exception to the agreement. As a result, the remaining unrecognized tax benefit was released and recorded as a payable to the IRS. 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. Xcel Energy filed a protest with the IRS. As of Dec. 31, 2018, the case has been forwarded to the Office of Appeals and Xcel Energy has recognized its best estimate of income tax expense that will result from a final resolution of this issue; however, the outcome and timing of a resolution is unknown. In the fourth quarter of 2018, the IRS began an audit of tax years 2014 - 2016 , however no adjustments have been proposed. State Audits — NSP-Wisconsin is a member of the Xcel Energy affiliated group that files consolidated state income tax returns. As of Dec. 31, 2018, NSP-Wisconsin’s earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations is 2014 . In the third quarter of 2018, the Wisconsin audit of tax years 2012 - 2013 concluded with no material adjustments. In the fourth quarter of 2018, Wisconsin began an audit of tax years 2014 - 2016 . No material adjustments have been proposed. Unrecognized Tax Benefits — 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 to the taxing authority to an earlier period. Unrecognized tax benefits - permanent vs. temporary: (Millions of Dollars) Dec. 31, 2018 Dec. 31, 2017 Unrecognized tax benefit — Permanent tax positions $ 2.0 $ 1.4 Unrecognized tax benefit — Temporary tax positions 0.8 1.0 Total unrecognized tax benefit $ 2.8 $ 2.4 Changes in unrecognized tax benefits: (Millions of Dollars) 2018 2017 2016 Balance at Jan. 1 $ 2.4 $ 5.3 $ 4.5 Additions based on tax positions related to the current year 0.2 0.4 0.5 Reductions based on tax positions related to the current year (0.1 ) (0.3 ) — Additions for tax positions of prior years 0.7 1.3 0.5 Reductions for tax positions of prior years (0.3 ) (4.3 ) (0.2 ) Settlements with taxing authorities (0.1 ) — — Balance at Dec. 31 $ 2.8 $ 2.4 $ 5.3 Unrecognized tax benefits were reduced by tax benefits associated with NOL and tax credit carryforwards: (Millions of Dollars) Dec. 31, 2018 Dec. 31, 2017 NOL and tax credit carryforwards $ (2.1 ) $ (1.9 ) Net deferred tax liability associated with the unrecognized tax benefit amounts and related NOLs and tax credits carryforwards were $1.1 million and $0.8 million for Dec. 31, 2018 and Dec. 31, 2017, respectively. As the IRS Appeals and federal and Wisconsin audits progress, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $2.2 million in the next 12 months. Payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryforwards. Payables for interest related to unrecognized tax benefits at Dec. 31, 2018, 2017 and 2016 were not material. No amounts were accrued for penalties related to unrecognized tax benefits as of Dec. 31, 2018, 2017 or 2016. Other Income Tax Matters — NOL amounts represent the tax loss that is carried forward and tax credits represent the deferred tax asset. NOL and tax credit carryforwards as of Dec. 31 were as follows: (Millions of Dollars) 2018 2017 Federal NOL carryforward $ — $ 57.8 Federal tax credit carryforwards 4.7 4.3 State NOL carryforward 2.5 5.4 Federal carryforward periods expire between 2021 and 2038 and state carryforward periods expire between 2031 and 2033 . Total income tax expense from operations differs from the amount computed by applying the statutory federal income tax rate to income before income tax expense. Effective income tax rate for years ended Dec. 31: 2018 2017 (a) 2016 (a) Federal statutory rate 21.0 % 35.0 % 35.0 % State income tax on pretax income, net of federal tax effect 6.2 % 5.1 % 5.1 % Increases (decreases) in tax from: Regulatory differences - ARAM (b) (4.3 ) (0.1 ) (0.2 ) Regulatory differences - deferral of ARAM (c) 4.1 — — Regulatory differences - other utility plant items (1.3 ) (1.7 ) (0.6 ) Tax credits recognized, net of federal income tax expense (0.8 ) (1.0 ) (0.7 ) Adjustments attributable to tax returns (0.6 ) (2.3 ) (0.3 ) Change in unrecognized tax benefits 0.4 0.8 0.1 Tax reform — — — Other, net 0.1 — (0.1 ) Effective income tax rate 24.8 % 35.8 % 38.3 % (a) Prior periods have been reclassified to conform to current year presentation. (b) ARAM is a method to flow back excess deferred taxes to customers. (c) ARAM has been deferred when regulatory treatment has not been established. As Xcel Energy received direction from its regulatory commissions regarding the return of excess deferred taxes to customers, the ARAM deferral was reversed. This resulted in a reduction to tax expense with a corresponding reduction to revenue. Components of income tax expense for years ended Dec. 31: (Millions of Dollars) 2018 2017 2016 Current federal tax expense $ 7.6 $ 2.8 $ 5.4 Current state tax expense 1.7 — 0.1 Current change in unrecognized tax expense (benefit) 0.2 (3.7 ) 0.5 Deferred federal tax expense 15.6 32.9 29.6 Deferred state tax expense 7.4 8.0 8.2 Deferred change in unrecognized tax expense (benefit) 0.3 4.7 (0.4 ) Deferred ITCs (0.5 ) (0.5 ) (0.5 ) Total income tax expense $ 32.3 $ 44.2 $ 42.9 Components of deferred income tax expense as of Dec. 31: (Millions of Dollars) 2018 2017 2016 Deferred tax expense (benefit) excluding items below $ 24.0 $ (173.9 ) $ 39.5 Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities (0.7 ) 219.5 (2.1 ) Deferred tax expense $ 23.3 $ 45.6 $ 37.4 Components of net deferred tax liability as of Dec. 31: (Millions of Dollars) 2018 2017 Deferred tax liabilities: Difference between book and tax bases of property $ 281.1 $ 269.5 Regulatory assets 55.4 58.4 Pension expense 13.9 14.2 Other 6.9 7.0 Total deferred tax liabilities $ 357.3 $ 349.1 Deferred tax assets: Regulatory liabilities $ 53.4 $ 55.8 NOL carryforward 0.4 12.6 Environmental remediation 7.8 8.1 Tax credit carryforward 4.7 4.6 Other employee benefits 4.1 3.9 Deferred ITCs 3.0 3.2 Other 3.2 4.2 Total deferred tax assets $ 76.6 $ 92.4 Net deferred tax liability $ 280.7 $ 256.7

Fair Value of Financial Assets

Fair Value of Financial Assets and Liabilities	12 Months Ended
	Dec. 31, 2018
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 disclosures about assets and liabilities measured at fair value. A hierarchical framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value is established by this guidance. • Level 1 — Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. The types of assets and liabilities included in Level 1 are highly liquid and actively traded instruments with quoted prices. • Level 2 — Pricing inputs are other than quoted prices in active markets, but are either directly or indirectly observable as of the reporting date. The types of assets and liabilities included in Level 2 are typically either comparable to actively traded securities or contracts, or priced with models using highly observable inputs. • Level 3 — Significant inputs to pricing have little or no observability as of the reporting date. The types of assets and liabilities included in Level 3 are those valued with models requiring significant management judgment or estimation. Specific valuation methods include: 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 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. As of Dec. 31, 2018, accumulated other comprehensive loss related to interest rate derivatives included no net gains or 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. Gross notional amounts of commodity options at Dec. 31: (Amounts in Millions) (a) (b) 2018 2017 MMBtu of natural gas 1.2 — (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 counterparties to its interest rate derivatives and commodity derivative contracts prior to settlement, and assesses each counterparty’s ability to perform on the transactions set forth in the contracts. Impact of credit risk was immaterial to the fair value of unsettled commodity derivatives presented in the consolidated balance sheets. Qualifying Cash Flow Hedges — Financial 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: (Millions of Dollars) 2018 2017 2016 Accumulated other comprehensive loss related to cash flow hedges at Jan. 1 $ (0.1 ) $ (0.1 ) $ (0.2 ) After-tax net realized losses on derivative transactions reclassified into earnings 0.1 — 0.1 Accumulated other comprehensive loss related to cash flow hedges at Dec. 31 $ — $ (0.1 ) $ (0.1 ) Pre-tax losses related to interest rate derivatives reclassified from accumulated other comprehensive loss into earnings were $0.1 million for the years ended Dec. 31, 2018, 2017 and 2016. Changes in the fair value of natural gas commodity derivatives resulted in net losses of $0.1 million , $0.3 million and $0.2 million for the years ended Dec. 31, 2018, 2017 and 2016, respectively, 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, 2018, 2017 and 2016, $0.3 million of natural gas commodity derivatives settlement gains, $0.2 million of settlement losses and $0.8 million of settlement losses, respectively, were recognized 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, 2018, 2017 and 2016. Recurring Fair Value Measurements — The following table presents for each of the fair value hierarchy levels, NSP-Wisconsin’s derivative assets measured at fair value on a recurring basis at Dec. 31, 2018 : Dec. 31, 2018 Fair Value Fair Value Total Netting (a) (Millions of Dollars) Level 1 Level 2 Level 3 Total (b) Current derivative assets Natural gas commodity $ — $ 0.2 $ — $ 0.2 $ — $ 0.2 (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, 2018. The counterparty netting excludes 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 $3.3 million at Dec. 31, 2018 in the consolidated balance sheet. NSP-Wisconsin had immaterial derivative assets measured at fair value on a recurring basis at Dec. 31, 2017. Fair Value of Long-Term Debt As of Dec. 31, other financial instruments for which the carrying amount did not equal fair value: 2018 2017 (Millions of Dollars) Carrying Amount Fair Value Carrying Amount Fair Value Long-term debt, including current portion $ 807.5 $ 850.4 $ 761.2 $ 856.1 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. Fair value estimates are based on information available to management as of Dec. 31, 2018 and 2017 , and given the observability of the inputs, fair values presented for long-term debt were assigned as Level 2.

Benefit Plans and Other Postret

Benefit Plans and Other Postretirement Benefits	12 Months Ended
	Dec. 31, 2018
Retirement Benefits [Abstract]
Benefit Plans and Other Postretirement Benefits	Benefit Plans and Other Postretirement Benefits Pension and Postretirement Health Care Benefits Xcel Energy has several noncontributory, defined benefit pension plans that cover almost all employees. Generally, benefits are based on a combination of years of service and average pay. Xcel Energy’s policy is to fully fund into an external trust the actuarially determined pension costs subject to the limitations of applicable employee benefit and tax laws. In addition to the qualified pension plans, Xcel Energy maintains a SERP and a nonqualified pension plan. The SERP is maintained for certain executives that were participants in the plan in 2008, when the SERP was closed to new participants. The nonqualified pension plan provides benefits for compensation that is in excess of the limits applicable to the qualified pension plans, with distributions funded by Xcel Energy’s consolidated operating cash flows. Obligations of the SERP and nonqualified plan as of Dec. 31, 2018 and 2017 were $33 million and $37 million , respectively, of which $1 million and $1 million , respectively, were attributable to NSP-Wisconsin. Xcel Energy recognized net benefit cost for the SERP and nonqualified plans of $4 million and $5 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. Xcel Energy has a contributory health and welfare benefit plan that provides health care and death benefits to certain Xcel Energy retirees. • NSP-Wisconsin discontinued subsidizing health care benefits for non-bargaining employees retiring after 1998 and for bargaining employees who retired after 1999. Xcel Energy bases the investment-return assumption on expected long-term performance for each of the asset classes in its pension and postretirement health care portfolios. For pension assets, Xcel Energy considers the historical returns achieved by its asset portfolio over the past 20 years longer period, as well as the long-term projected return levels. Xcel Energy and NSP-Wisconsin continually review their pension assumptions. Pension cost determination assumes a forecasted mix of investment types over the long-term. • Investment returns in 2018 were below the assumed level of 7.10% ; • Investment returns in 2017 were above the assumed level of 7.10% ; • Investment returns in 2016 were below the assumed level of 7.10% ; and • In 2019, NSPW-Wisconsin’s expected investment-return assumption is 7.10% . Pension plan and postretirement benefit assets are invested in a portfolio according to Xcel Energy’s return, liquidity and diversification objectives to provide a source of funding for plan obligations and minimize contributions to the plan, within appropriate levels of risk. The principal mechanism for achieving these objectives is the asset allocation given the long-term risk, return, correlation and liquidity characteristics of each particular asset class. There were no significant concentrations of risk in any industry, index, or entity. Market volatility can impact even well-diversified portfolios and significantly affect the return levels achieved by the assets in any year. State agencies also have issued guidelines to the funding of postretirement benefit costs. Xcel Energy’s ongoing investment strategy is based on plan-specific investment recommendations that seek to minimize potential investment and interest rate risk as a plan’s funded status increases over time. The investment recommendations result in a greater percentage of long-duration fixed income securities being allocated to specific plans having relatively higher funded status ratios and a greater percentage of growth assets being allocated to plans having relatively lower funded status ratios. Plan Assets The following presents, for each of the fair value hierarchy levels, NSP-Wisconsin’s pension plan assets measured at fair value: Dec. 31, 2018 (a) Dec. 31, 2017 (a) (Thousands of Dollars) Level 1 Level 2 Level 3 Measured at NAV Total Level 1 Level 2 Level 3 Measured at NAV Total Cash equivalents $ 4.9 $ — $ — $ — $ 4.9 $ 8.1 $ — $ — $ — $ 8.1 Commingled funds: 37.1 — — 41.8 78.9 43.2 — — 45.9 89.1 Debt securities: — 22.2 — — 22.2 — 24.1 — — 24.1 Equity securities: 4.6 — — — 4.6 4.9 — — — 4.9 Other — 0.2 — (1.3 ) (1.1 ) (1.3 ) 0.1 — — (1.2 ) Total $ 46.6 $ 22.4 $ — $ 40.5 $ 109.5 $ 54.9 $ 24.2 $ — $ 45.8 $ 124.9 (a) See Note 8 for further information on fair value measurement inputs and methods. The following presents, for each of the fair value hierarchy levels, NSP-Wisconsin’s postretirement benefit plan assets that were measured at fair value: Dec. 31, 2018 (a) Dec. 31, 2017 (a) (Millions of Dollars) Level 1 Level 2 Level 3 Measured at NAV Total Level 1 Level 2 Level 3 Measured at NAV Total Cash equivalents $ — $ — $ — $ — $ — $ 0.1 $ — $ — $ — $ 0.1 Insurance contracts — 0.1 — — 0.1 — 0.1 — — 0.1 Commingled funds 0.1 — — — 0.1 0.3 — — — 0.3 Debt securities — 0.2 — — 0.2 — 0.5 — — 0.5 Equity securities — — — — — 0.1 — — — 0.1 Total $ 0.1 $ 0.3 $ — $ — $ 0.4 $ 0.5 $ 0.6 $ — $ — $ 1.1 (a) See Note 8 for further information on fair value measurement inputs and methods. No assets were transferred in or out of Level 3 for 2018 and 2017. Funded Status — Comparisons of the actuarially computed benefit obligation, changes in plan assets and funded status of the pension and postretirement health care plans for NSP-Wisconsin are as follows: Pension Benefits Postretirement Benefits (Millions of Dollars) 2018 2017 2018 2017 Change in Benefit Obligation: Obligation at Jan. 1 $ 156.8 $ 157.5 $ 16.4 $ 15.0 Service cost 4.8 4.6 — — Interest cost 5.4 6.2 0.6 0.6 Plan participants’ contributions — — — 0.1 Plan amendments — (0.7 ) — — Actuarial (gain) loss (13.4 ) 6.5 (3.3 ) 2.1 Benefit payments (a) (13.8 ) (17.3 ) (0.9 ) (1.4 ) Obligation at Dec. 31 $ 139.8 $ 156.8 $ 12.8 $ 16.4 Change in Fair Value of Plan Assets: Fair value of plan assets at Jan. 1 $ 124.9 $ 119.0 $ 1.1 $ 0.5 Actual return on plan assets (11.1 ) 13.9 — — Plan participants’ contributions — — — 0.1 Employer contributions 9.5 9.3 0.2 1.9 Benefit payments (13.8 ) (17.3 ) (0.9 ) (1.4 ) Fair value of plan assets at Dec. 31 $ 109.5 $ 124.9 $ 0.4 $ 1.1 Funded status of plans at Dec. 31 $ (30.3 ) $ (31.9 ) $ (12.4 ) $ (15.3 ) Amounts recognized in the Consolidated Balance Sheet at Dec. 31: Current liabilities $ — $ — $ (0.8 ) $ (0.3 ) Noncurrent liabilities (30.3 ) (31.9 ) (11.6 ) (15.0 ) Net amounts recognized $ (30.3 ) $ (31.9 ) $ (12.4 ) $ (15.3 ) Significant Assumptions Used to Measure Benefit Obligations: Discount rate for year-end valuation 4.31 % 3.63 % 4.32 % 3.62 % Expected average long-term increase in compensation level 3.75 3.75 N/A N/A Mortality table RP-2014 RP-2014 RP-2014 RP-2014 Health care costs trend rate — initial: Pre-65 N/A N/A 6.5 % 7.0 % Health care costs trend rate — initial: Post-65 N/A N/A 5.3 % 5.5 % Ultimate trend assumption — initial: Pre-65 N/A N/A 4.5 % 4.5 % Ultimate trend assumption — initial: Post-65 N/A N/A 4.5 % 4.5 % Years until ultimate trend is reached N/A N/A 4 5 (a) Includes approximately $198 million , of which $10.4 million was attributable to NSP-Wisconsin, of lump-sum benefit payments used in the determination of a settlement charge. Accumulated benefit obligation for the pension plan was $129.4 million and $145.4 million as of Dec. 31, 2018 and 2017, respectively. Net Periodic Benefit Cost (Credit) — Net periodic benefit cost (credit) other than the service cost component is included in other income in the consolidated statement of income. Components of net periodic benefit cost (credit) and the amounts recognized in other comprehensive income and regulatory assets and liabilities: Pension Benefits Postretirement Benefits (Millions of Dollars) 2018 2017 2016 2018 2017 2016 Service cost $ 4.8 $ 4.6 $ 4.4 $ — $ — $ — Interest cost 5.4 6.2 6.9 0.6 0.6 0.7 Expected return on plan assets (9.0 ) (9.2 ) (9.2 ) (0.1 ) — — Amortization of prior service credit — 0.1 0.1 (0.4 ) (0.4 ) (0.4 ) Amortization of net loss 5.7 5.9 5.4 0.6 0.4 0.3 Settlement charge (a) 7.2 7.1 — — — — Net periodic pension cost (credit) $ 14.1 $ 14.7 $ 7.6 $ 0.7 $ 0.6 $ 0.6 Costs not recognized due to effects of regulation (3.4 ) (4.2 ) — — — — Net benefit cost (credit) recognized for financial reporting $ 10.7 $ 10.5 $ 7.6 $ 0.7 $ 0.6 $ 0.6 Significant Assumptions Used to Measure Costs: Discount rate 3.63 % 4.13 % 4.66 % 3.62 % 4.13 % 4.65 % Expected average long-term increase in compensation level 3.75 3.75 4.00 — — — Expected average long-term rate of return on assets 7.10 7.10 7.10 5.30 5.80 5.80 (a) A settlement charge is required when the amount of all 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 2018 and 2017, as a result of lump-sum distributions during the 2018 and 2017 plan years, NSP-Wisconsin recorded a total pension settlement charge of $7.2 million in 2018 and $7.1 million in 2017, a total of $2 million and $2 million of that amount was recorded in the income statement in 2018 and 2017. Pension costs include an expected return for the current year that may differ from actual investment performance in the plan. Return assumption used for 2019 pension cost calculations is 7.10% . Pension Benefits Postretirement Benefits (Millions of Dollars) 2018 2017 2018 2017 Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost: Net loss $ 74.3 $ 80.4 $ 6.8 $ 10.6 Prior service credit (0.3 ) (0.3 ) (1.4 ) (1.8 ) Total $ 74.0 $ 80.1 $ 5.4 $ 8.8 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 $ 5.3 $ 5.5 $ 0.2 $ 0.1 Noncurrent regulatory assets 68.7 74.6 5.2 8.7 Total $ 74.0 $ 80.1 $ 5.4 $ 8.8 Measurement date Dec. 31, 2018 Dec. 31, 2017 Dec. 31, 2018 Dec. 31, 2017 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 2016 - 2019 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 2019, of which $7 million was attributable to NSP-Wisconsin; • $150 million in 2018, of which $10 million was attributable to NSP-Wisconsin; • $162 million in 2017, of which $9 million was attributable to NSP-Wisconsin; and, • $125 million in 2016, of which $7 million was attributable to NSP-Wisconsin. For future years, Xcel Energy and NSP-Wisconsin anticipate contributions will be made as necessary. The postretirement health care plans have no funding requirements other than fulfilling benefit payment obligations, when claims are presented and approved. Additional cash funding requirements are prescribed by certain state and federal rate regulatory authorities. Xcel Energy, which includes NSP-Wisconsin, contributed $11 million during 2018, $20 million during 2017, $18 million during 2016, of which $0.3 million , $2 million and $1 million were attributable to NSP-Wisconsin. Xcel Energy expects to contribute approximately $11 million during 2019, of which $1 million is attributable to NSP-Wisconsin. Target asset allocations: Pension Benefits Postretirement Benefits 2018 2017 2018 2017 Domestic and international equity securities 37 % 38 % 18 % 24 % Long-duration fixed income and interest rate swap securities 28 23 — — Short-to-intermediate fixed income securities 18 21 70 60 Alternative investments 15 16 8 9 Cash 2 2 4 7 Total 100 % 100 % 100 % 100 % Plan Amendments — Xcel Energy, which includes NSP-Wisconsin, amended the Xcel Energy Pension Plan and Xcel Energy Inc. Nonbargaining Pension Plan (South) 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. In 2018 and 2017, there were no plan amendments made which affected the postretirement benefit obligation. Projected Benefit Payments NSP-Wisconsin’s projected benefit payments: (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 2019 $ 14.6 $ 1.2 $ — $ 1.2 2020 10.9 1.1 — 1.1 2021 10.9 1.1 — 1.1 2022 10.8 1.0 — 1.0 2023 11.1 1.0 — 1.0 2024-2028 55.5 4.2 — 4.2 Defined Contribution Plans Xcel Energy, which includes NSP-Wisconsin, maintains 401(k) and other defined contribution plans that cover most employees. The expense to these plans for NSP-Wisconsin was approximately $2 million in 2018 and $1 million in 2017 and 2016. 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.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2018
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Commitments and Contingencies Legal 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 complex judgments about future events. Management maintains accruals for 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 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. Gas Trading Litigation — 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. Multiple lawsuits seeking monetary damages were commenced against e prime and its affiliates, including Xcel Energy, between 2003 and 2009 alleging fraud and anticompetitive activities in conspiring to restrain the trade of natural gas and manipulate natural gas prices. Cases were all consolidated in the U.S. District Court in Nevada. In the fourth quarter of 2018, four cases were settled. Two cases remain active which include an MDL matter consisting of a Colorado class (Breckenridge), and a Wisconsin class (Arandell Corp.). Breckenridge/Colorado — Case has been remanded to the MDL panel and is expected to be referred back to the U.S. District court in Colorado. Xcel Energy has concluded that a loss is a remote. Arandell Corp. — 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 were denied in March 2017. Plaintiffs have asked the lower court to remand the cases back to the court where the actions were originally filed anticipating class certification. A hearing date has not been set. Xcel Energy has concluded that a loss is remote. Rate Matters MISO ROE Complaints — In November 2013 and February 2015, customers filed complaints against MISO TOs including NSP-Minnesota and NSP-Wisconsin. The first complaint argued for a reduction in the base ROE in MISO transmission formula rates from 12.38% to 9.15% , and removal of ROE adders (including those for RTO membership). The second complaint sought to reduce base ROE from 12.38% to 8.67% . In September 2016, the FERC issued an order granting a 10.32% base ROE ( 10.82% with the RTO adder) effective for the first complaint period of Nov. 12, 2013 to Feb. 11, 2015 and subsequent to the date of the order. The D.C. Circuit subsequently vacated and remanded FERC Opinion No. 531, which had established the ROE methodology on which the September 2016 FERC order was based. In October 2018, the FERC issued a New England Transmission Owners base ROE order that addressed the D.C. Circuit’s actions on Opinion No. 531. Under a new proposed two step ROE approach, the FERC has indicated an intention to dismiss an ROE complaint if the existing ROE falls within the range of just and reasonable ROEs based on equal weighting of the DCF, CAPM, and Expected Earnings models. The FERC proposes that if necessary, it would then set a new ROE by averaging the results of these models plus a Risk Premium model. With respect to the MISO TOs, the FERC subsequently made preliminary determinations in a November 2018 order that the MISO base ROE in effect for the first complaint period ( 12.38% ) was outside the range of reasonableness, and should be reduced. The FERC indicated its preliminary analysis using the new ROE approach resulted in a base ROE of 10.28% for the first compliant period, compared to the previously ordered base ROE of 10.32% . A procedural schedule has been set for the first half of 2019, with the FERC expected to act no earlier than the second half of 2019. NSP-Minnesota has recognized a current refund liability consistent with its best estimate of the final ROE. Environmental New and changing federal and state environmental mandates can create financial liabilities for NSP-Wisconsin, which are normally recovered through the regulated rate process. Site Remediation — Various federal and state environmental laws impose liability where hazardous substances or other regulated materials have been released to the environment. NSP-Wisconsin may sometimes pay all or a portion of the cost to remediate sites where past activities of NSP-Wisconsin’s predecessors or other parties have caused environmental contamination. Environmental contingencies could arise from various situations, including sites of former MGPs; and third-party sites, such as landfills, for which NSP-Wisconsin is alleged to have sent wastes to that site. MGP Sites Ashland MGP Site — NSP-Wisconsin was named a responsible party for contamination at the Ashland/Northern States Power Lakefront Superfund Site (the Site) in Ashland, Wisconsin. Remediation and restoration activities are anticipated to be completed in 2019 and groundwater treatment activities at the Site will continue for many years. Current cost estimate for the remediation of the entire site is approximately $192 million , of which approximately $165 million has been spent. As of Dec. 31, 2018 and 2017, NSP-Wisconsin had recorded a total liability of $27 million and $30 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 10 -year period and to apply a 3% carrying cost to the unamortized regulatory asset. MGP, Landfill or Disposal Sites — NSP-Wisconsin is currently investigating or remediating two MGP, landfill or other disposal sites across its service territories, in addition to the Ashland MGP Site, and these activities will continue through at least 2019. NSP-Wisconsin accrued $1.7 million as of Dec. 31, 2018, and $0.1 million as of Dec. 31, 2017 for these sites. There may be insurance recovery and/or recovery from other potentially responsible parties, offsetting some portion of costs incurred. Environmental Requirements — Water and Waste Federal CWA WOTUS Rule — In 2015, the EPA and Corps published a final rule that significantly broadened the scope of waters under the CWA that are subject to federal jurisdiction, referred to as “WOTUS”. The Rule has been subject to significant litigation and is currently stayed in a portion of the country. NSP-Wisconsin cannot estimate potential impacts until the legal and administrative processes are finalized, but expects costs will be recoverable through regulatory mechanisms. Federal CWA Section 316(b) — The federal CWA requires the EPA to regulate cooling water intake structures to assure that these structures reflect the best technology available for minimizing impingement and entrainment of aquatic species. NSP-Wisconsin estimates the likely cost for complying with impingement requirements is approximately $4 million , to be incurred between 2019 and 2028, while the total cost of entrainment improvements is anticipated to be immaterial. NSP-Wisconsin believes two plants could be required by state regulators to make improvements to reduce entrainment. NSP-Wisconsin anticipates these costs will be fully recoverable through regulatory mechanisms. AROs — AROs have been recorded for NSP-Wisconsin’s assets. NSP-Wisconsin’s AROs were as follows: Dec. 31, 2018 (Millions of Dollars) Jan. 1, 2018 Accretion Cash Flow Revisions (a) Dec. 31, 2018 (b) Electric Distribution $ — $ — $ 4.6 $ 4.6 Steam production 3.7 0.1 — 3.8 Miscellaneous 0.4 — — 0.4 Natural gas Distribution 10.3 0.4 (1.6 ) 9.1 Total liability (c) $ 14.4 $ 0.5 $ 3.0 $ 17.9 (a) In 2018, AROs were revised for changes in timing and estimates of cash flows. Changes in gas distribution AROs were mainly related to increased gas line mileage and number of services, which were more than offset by increased discount rates. Changes in electric distribution AROs primarily related to increased labor costs. (b) There were no ARO amounts incurred or settled in 2018. (c) Included in other long-term liabilities balance in the consolidated balance sheet. Dec. 31, 2017 (Millions of Dollars) Jan. 1, 2017 Amounts Incurred (a) Accretion Cash Flow Revisions (b) Dec. 31, 2017 (c) Electric Steam production $ 2.7 $ 1.0 $ — $ — $ 3.7 Miscellaneous 0.4 — — — 0.4 Natural gas Distribution 8.3 — 0.3 1.7 10.3 Total liability (d) $ 11.4 $ 1.0 $ 0.3 $ 1.7 $ 14.4 (a) Amounts incurred related to asbestos at the French Island plant. (b) Changes in gas distribution AROs were primarily related to increased labor costs. (c) There were no ARO amounts settled in 2017. (d) Included in other long-term liabilities balance in the consolidated balance sheet. Indeterminate AROs — Outside of the 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 cost of removal could be determined as of Dec. 31, 2018. Therefore, an ARO has not been recorded for these facilities. Removal Costs — NSP-Wisconsin records a regulatory liability for the plant removal costs that are recovered currently in rates. These removal costs have accumulated based on varying rates as authorized by the appropriate regulatory entities. NSP-Wisconsin has estimated the amount of removal costs accumulated through historic depreciation expense based on current factors used in the existing depreciation rates. Removal costs as of Dec. 31, 2018 and 2017 were $158 million and $146 million , respectively. Joint Operating System — The electric production and transmission system of NSP-Wisconsin is managed 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 from any nuclear incident is limited to $14.1 billion under the Price-Anderson amendment to the Atomic Energy Act. NSP-Minnesota has secured $450.0 million of coverage for its public liability exposure with a pool of insurance companies. The remaining $13.6 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 $137.6 million per reactor-incident for each of its three licensed reactors, for public liability arising from a nuclear incident at any licensed nuclear facility in the United States. The maximum funding requirement is $20.5 million per reactor-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 November 2018. NSP-Minnesota purchases insurance for property damage and site decontamination cleanup costs from NEIL and 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. NSP-Minnesota could be subject to annual maximum assessments of approximately $18.0 million for business interruption insurance and $39.0 million for property damage insurance if losses exceed accumulated reserve funds. 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 for NSP-Wisconsin for the year ended Dec. 31: (Millions of Dollars) 2018 2017 2016 Total expense $ 1.3 $ 1.2 $ 1.2 Future commitments under operating leases are: (Millions of Dollars) 2019 $ 1.0 2020 0.9 2021 0.8 2022 0.8 2023 0.8 Thereafter 3.8 Total $ 8.1 Fuel Contracts — NSP-Wisconsin has entered into various long-term commitments for the purchase and delivery of a significant portion of its coal and natural gas requirements. These contracts expire between 2019 and 2029 . 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 2% 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. Estimated minimum purchases under these contracts as of Dec. 31, 2018 : (Millions of Dollars) Coal Natural gas Natural gas 2019 $ 6.1 $ 9.9 $ 13.4 2020 2.3 0.3 11.8 2021 0.6 0.4 11.3 2022 0.7 0.2 9.7 2023 0.7 — 7.9 Thereafter — — 24.3 Total (a) $ 10.4 $ 10.8 $ 78.4 (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. VIEs — 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 partnerships to be VIEs primarily due to contractual arrangements within each limited partnership that establishes sharing of ongoing voting control and profits and losses that do not align with the partners’ proportional equity ownership. NSP-Wisconsin has the power to direct the activities that most significantly impact these entities’ economic performance. Therefore, NSP-Wisconsin consolidates these limited partnerships in its consolidated financial statements. NSP-Wisconsin’s risk of loss for these partnerships 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. Amounts reflected in NSP-Wisconsin’s consolidated balance sheets for low-income housing limited partnerships include the following: (Millions of Dollars) Dec. 31, 2018 Dec. 31, 2017 Current assets $ 0.3 $ 0.4 Property, plant and equipment, net 0.9 1.9 Other noncurrent assets 0.1 0.1 Total assets $ 1.3 $ 2.4 Current liabilities $ — $ 1.2 Mortgages and other long-term debt payable 0.5 0.5 Other noncurrent liabilities — 0.1 Total liabilities $ 0.5 $ 1.8 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) Guarantor Guarantee Current Triggering Guarantee of customer loans for the Farm Rewiring Program (a) NSP-Wisconsin $ 1.0 $ — (b) (a) The term of this guarantee expires in 2020 , which is the final scheduled repayment date for the loans. As of Dec. 31, 2018, no claims had been made by the lender. (b) The debtor becomes the subject of bankruptcy or other insolvency proceedings.

Other Comprehensive Income

Other Comprehensive Income	12 Months Ended
	Dec. 31, 2018
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, 2018 and 2017 : Gains and Losses on Cash Flow Hedges (Millions of Dollars) 2018 2017 Accumulated other comprehensive loss at Jan. 1 $ (0.1 ) $ (0.1 ) Losses reclassified from net accumulated other comprehensive loss (net of taxes of $0 and $0), respectively (a) 0.1 — Net current period other comprehensive income 0.1 — Accumulated other comprehensive loss at Dec. 31 $ — $ (0.1 ) (a) Included in interest charges.

Segments and Related Informatio

Segments and Related Information	12 Months Ended
	Dec. 31, 2018
Segment Reporting [Abstract]
Segment Information	Segments and Related Information Operating results from 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 - The regulated electric utility segment generates electricity which is transmitted and distributed in Wisconsin and Michigan. • Regulated Natural Gas - The regulated natural gas utility segment purchases, transports, stores and distributes natural gas in portions of Wisconsin and Michigan. • All Other - 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. NSP-Wisconsin’s segment information is as follows: (Millions of Dollars) 2018 2017 2016 Regulated Electric Operating revenues (a) $ 878.6 $ 881.9 $ 849.9 Intersegment revenues 0.4 0.5 0.4 Total operating revenue $ 879.0 $ 882.4 $ 850.3 Depreciation and amortization 97.8 88.9 81.3 Interest charges and financing costs 31.8 29.4 29.7 Income tax expense 28.4 38.9 40.5 Net income 85.5 70.9 65.0 Regulated Natural Gas Operating revenues (a) $ 141.6 $ 122.4 $ 106.2 Intersegment revenues 0.4 0.3 0.5 Total operating revenue $ 142.0 $ 122.7 $ 106.7 Depreciation and amortization 28.1 22.1 16.8 Interest charges and financing costs 3.3 2.8 2.9 Income tax expense 4.5 4.0 2.4 Net income 12.5 7.8 4.5 All Other Operating revenues (a) $ 1.3 $ 1.2 $ 1.1 Depreciation and amortization 0.2 0.2 0.2 Interest charges and financing costs 0.1 — — Income tax (benefit) (0.6 ) 1.3 — Net (loss) — 0.7 (0.4 ) Consolidated Total Total operating revenue $ 1,022.3 $ 1,006.3 $ 958.1 Reconciling eliminations (0.8 ) (0.8 ) (0.9 ) Consolidated total revenue $ 1,021.5 $ 1,005.5 $ 957.2 Depreciation and amortization 126.1 111.2 98.3 Interest charges and financing costs 35.2 32.2 32.6 Income tax expense 32.3 44.2 42.9 Net income 98.0 79.4 69.1 (a) Operating revenues include $157.9 million , $177.2 million and $170.5 million of intercompany revenue for the years ended Dec. 31, 2018, 2017 and 2016, respectively. See Note 13 for further information.

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2018
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. Significant affiliate transactions among the companies and related parties including billings under the Interchange Agreement for the years ended Dec. 31: (Millions of Dollars) 2018 2017 2016 Operating revenues: Electric $ 157.9 $ 177.2 $ 170.4 Operating expenses: Purchased power 410.9 421.6 413.6 Transmission expense 62.8 68.6 61.9 Other operating expenses — paid to Xcel Energy Services Inc. 86.9 92.7 106.5 Accounts receivable and payable with affiliates at Dec. 31 were: 2018 2017 (Millions of Dollars) Accounts Accounts Accounts Accounts NSP-Minnesota $ — $ 11.0 $ — $ 17.8 PSCo 0.2 — — — Other subsidiaries of Xcel Energy Inc. 14.9 9.0 3.4 11.8 $ 15.1 $ 20.0 $ 3.4 $ 29.6

Summarized Quarterly Financial

Summarized Quarterly Financial Data (Unaudited)	12 Months Ended
	Dec. 31, 2018
Quarterly Financial Information Disclosure [Abstract]
Summarized Quarterly Financial Data (Unaudited)	Summarized Quarterly Financial Data (Unaudited) Quarter Ended (Millions of Dollars) March 31, 2018 June 30, 2018 Sept. 30, 2018 Dec. 31, 2018 Operating revenues $ 273.1 $ 231.8 $ 256.0 $ 260.6 Operating income 49.0 27.5 48.0 34.9 Net income 31.4 15.2 31.0 20.4 Quarter Ended (Millions of Dollars) March 31, 2017 June 30, 2017 Sept. 30, 2017 Dec. 31, 2017 Operating revenues $ 264.9 $ 230.1 $ 247.5 $ 263.0 Operating income (a) 43.5 29.7 39.2 40.2 Net income 22.4 14.3 22.3 20.4

Schedule II, Valuation and Qual

Schedule II, Valuation and Qualifying Accounts	12 Months Ended
	Dec. 31, 2018
SEC Schedule, 12-09, Valuation and Qualifying Accounts [Abstract]
Schedule II, Valuation and Qualifying Accounts	NSP-WISCONSIN AND SUBSIDIARIES VALUATION AND QUALIFYING ACCOUNTS YEARS ENDED DEC. 31, 2018 , 2017 AND 2016 Allowance for bad debts (Millions of Dollars) 2018 2017 2016 Balance at Jan. 1 $ 4.9 $ 4.9 $ 5.1 Additions Charged to Costs and Expenses 4.2 4.1 3.7 Additions Charged to Other Accounts (a) 1.0 0.9 1.1 Deductions from Reserves (b) (4.5 ) (5.0 ) (5.0 ) Balance at Dec. 31 $ 5.6 $ 4.9 $ 4.9 (a) Recovery of amounts previously written off. (b) Deductions relate primarily to bad debt write-offs.

Summary of Significant Accoun_2

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2018
Accounting Policies [Abstract]
Business and System of Accounts	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. General — 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.
Principles of Consolidation	NSP-Wisconsin’s consolidated financial statements include its wholly-owned subsidiaries and VIEs 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 3 for further information.
Subsequent Events	NSP-Wisconsin has evaluated the impact of events occurring after Dec. 31, 2018 up to the date of issuance of these consolidated financial statements. These statements contain all necessary adjustments and disclosures resulting from that evaluation.
Use of Estimates	Use of Estimates — NSP-Wisconsin uses estimates based on the best information available in recording transactions and balances resulting from business operations. Estimates are used on items such as plant depreciable lives or potential disallowances, AROs, certain regulatory assets and liabilities, tax provisions, uncollectible amounts, environmental costs, unbilled revenues, jurisdictional fuel and energy cost allocations and actuarially determined benefit costs. Recorded estimates are revised when better information becomes available or when actual amounts can be determined. Those revisions can affect operating results.
Regulatory Accounting	Regulatory Accounting — NSP-Wisconsin accounts for income and expense items in accordance with accounting guidance for regulated operations. Under this guidance: • Certain costs, which would otherwise be charged to expense or other comprehensive income, are deferred as regulatory assets based on the expected ability to recover the costs in future rates; and • Certain credits, which would otherwise be reflected as income or other comprehensive income, are deferred as regulatory liabilities based on the expectation the amounts will be returned to customers in future rates, or because the amounts were collected in rates prior to the costs being incurred. Estimates of recovering deferred costs and returning deferred credits are based on specific ratemaking decisions or precedent for each item. Regulatory assets and liabilities are amortized consistent with the treatment in the rate setting process. If changes in the regulatory environment occur, NSP-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 results of operations, financial condition or cash flows. See Note 4 for further information.
Income Taxes	Income Taxes — NSP-Wisconsin accounts for income taxes using the asset and liability method, which require 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. Reversal of certain temporary differences are accounted for as current income tax expense due to the effects of past regulatory practices when deferred taxes were not required to be recorded due to the use of flow through accounting for ratemaking purposes. Tax credits are recorded when earned unless there is a requirement to defer the benefit and amortize it over the book depreciable lives of the related property. The requirement to defer and amortize tax credits only applies to federal ITCs related to public utility property. Utility rate regulation also has resulted in the recognition of regulatory assets and liabilities related to income taxes. Deferred tax assets are reduced by a valuation allowance if it is more likely than not that some portion or all of the deferred tax asset will not be realized. NSP-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 in the consolidated statements of income. Xcel Energy Inc. and its subsidiaries, including NSP-Wisconsin, file consolidated federal income tax returns as well as consolidated or separate state income tax returns. Federal income taxes paid by Xcel Energy Inc. are allocated to Xcel Energy Inc.’s subsidiaries based on separate company computations. A similar allocation is made for state income taxes paid by Xcel Energy Inc. in connection with consolidated state filings. Xcel Energy Inc. also allocates its own income tax benefits to its direct subsidiaries. See Note 7 for further information.
Property, Plant and Equipment and Depreciation	Property, Plant and Equipment and Depreciation — Property, plant and equipment is stated at original cost. The cost of plant includes direct labor and materials, contracted work, overhead costs and AFUDC. The cost of plant retired is charged to accumulated depreciation and amortization. Amounts recovered in rates for future removal costs are recorded as regulatory liabilities. Significant additions or improvements extending asset lives are capitalized, while repairs and maintenance costs are charged to expense as incurred. Maintenance and replacement of items determined to be less than a unit of property are charged to operating expenses as incurred. Planned maintenance activities are charged to operating expense unless the cost represents the acquisition of an additional unit of property or the replacement of an existing unit of property. Property, plant and equipment is tested for impairment when it is determined that the carrying value of the assets may not be recoverable. A loss is recognized in the current period if it becomes probable that part of a cost of a plant under construction or recently completed plant will be disallowed for recovery from customers and a reasonable estimate of the disallowance can be made. For investments in property, plant and equipment that are abandoned and not expected to go into service, incurred costs and related deferred tax amounts are compared to the discounted estimated future rate recovery, and a loss is recognized, if necessary. NSP-Wisconsin records depreciation expense 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 3.5% in 2018, 3.4% in 2017 and 3.3% in 2016. See Note 3 for further information.
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 10 for further information.
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 requires management to make various assumptions and estimates. Certain unrecognized actuarial gains and losses and unrecognized prior service costs or credits are deferred as regulatory assets and liabilities, rather than recorded as other comprehensive income, based on regulatory recovery mechanisms. See Note 9 for further information.
Environmental Costs	Environmental Costs — Environmental costs are recorded when it is probable NSP-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 are regularly adjusted as estimates are revised and remediation proceeds. If other participating potentially responsible parties exist and acknowledge their potential involvement with a site, costs are estimated and recorded only for NSP-Wisconsin’s expected share of the cost. Future costs of restoring sites are treated as a capitalized cost of plant retirement. The depreciation expense levels recoverable in rates include a provision for removal expenses. Removal costs recovered in rates before the related costs are incurred are classified as a regulatory liability. See Note 10 for further information.
Revenue From Contracts With Customers	Revenue From Contracts With Customers — Performance obligations related to the sale of energy are satisfied as energy is delivered to customers. NSP-Wisconsin recognizes revenue that corresponds to the price of the energy delivered to the customer. The measurement of energy sales to customers is generally based on the reading of their meters, which occurs 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 does not recognize a separate financing component of its collections from customers as contract terms are short-term in nature . NSP-Wisconsin presents its revenues net of any excise or sales taxes or fees. NSP-Wisconsin has various rate-adjustment mechanisms that provide for the recovery of natural gas, electric fuel and purchased energy costs. Cost-adjustment tariffs may increase or decrease the level of revenue collected from customers and are revised periodically for differences between the total amount collected under the clauses and the costs incurred. When applicable, fuel cost over-recoveries (the excess of fuel revenue billed to customers over fuel costs incurred) are deferred as regulatory liabilities and under-recoveries (the excess of fuel costs incurred over fuel revenues billed to customers) are deferred as regulatory assets. 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 2% annual tolerance band, for future rate recovery or refund, subject to PSCW approval.
Cash and Cash Equivalents	Cash and Cash Equivalents — NSP-Wisconsin considers investments in instruments with a remaining maturity of three months or less at the time of purchase, to be cash equivalents.
Accounts Receivable and Allowance for Bad Debts	Accounts Receivable and Allowance for Bad Debts — Accounts receivable are stated at the actual billed amount net of an allowance for bad debts. NSP-Wisconsin establishes an allowance for uncollectible receivables based on a policy that reflects its expected exposure to the credit risk of customers. As of Dec. 31, 2018 and 2017, the allowance for bad debts was $5.6 million and $4.9 million , respectively.
Inventory	Inventory — Inventory is recorded at average cost. As of Dec. 31, 2018, materials and supplies, fuel and natural gas inventory were $6.7 million , $3.8 million and $6.6 million , respectively. As of Dec. 31, 2017, materials and supplies, fuel and natural gas inventory were $6.9 million , $3.9 million and $7.0 million , respectively.
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 to establish fair value. For commodity derivatives, the most observable inputs available are generally used to determine the fair value of each contract. In the absence of a quoted price, NSP-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 8 and 9 for further information.
Derivative Instruments	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. Any derivative instruments not qualifying for the normal purchases and normal sales exception are recorded on the consolidated balance sheets at fair value as derivative instruments. Classification of changes in fair value for those derivative instruments is dependent on the designation of a qualifying hedging relationship. Changes in fair value of derivative instruments not designated in a qualifying hedging relationship are reflected in current earnings or as a regulatory asset or liability. Classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms. 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. Normal Purchases and Normal Sales — NSP-Wisconsin enters into contracts for purchases and sales of commodities for use in its operations. At inception, contracts are evaluated to determine whether a derivative exists and/or whether an instrument may be exempted from derivative accounting if designated as a normal purchase or normal sale. See Note 8 for further information.
AFUDC	AFUDC — AFUDC represents the cost of capital used to finance utility construction activity. AFUDC is computed by applying a composite financing rate to qualified CWIP. The amount of AFUDC capitalized as a utility construction cost is credited to other nonoperating income (for equity capital) and interest charges (for debt capital). AFUDC amounts capitalized are included in NSP-Wisconsin’s rate base for establishing utility service rates
Alternative revenue programs	Alternative Revenue — Certain rate rider mechanisms qualify as alternative revenue programs under GAAP. These mechanisms arise from costs imposed upon the utility by action of a regulator or legislative body related to an environmental, public safety or other mandate. When certain criteria are met, such as collection within 24 months , revenue is recognized equal to the revenue requirement, which may include return on rate base items and incentives. The mechanisms are revised periodically for differences between the total amount collected and the revenue recognized, which may increase or decrease the level of revenue collected from customers. Alternative revenues arising from these programs are presented on a gross basis and disclosed separately from revenue from contracts with customers in the period earned. See Note 6 for further information. 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% 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.
Emission Allowances	Emission Allowances — Emission allowances are recorded at cost plus broker commission fees. The inventory accounting model is utilized for all emission allowances and sales of these allowances are included in electric revenues.
Renewable Energy Credits	RECs — Cost of RECs that are utilized for compliance purposes is recorded as electric fuel and purchased power expense. Sales of RECs are recorded in electric revenues on a gross basis. The cost of these RECs are recorded in electric fuel and purchased power expense.

Property Plant and Equipment _2

Property Plant and Equipment Property Plant and Equipment (Tables)	12 Months Ended
	Dec. 31, 2018
Property, Plant and Equipment [Abstract]
Public Utility Property, Plant, and Equipment	(Millions of Dollars) Dec. 31, 2018 Dec. 31, 2017 Property, plant and equipment Electric plant $ 2,895.5 $ 2,602.7 Natural gas plant 345.7 326.7 Common and other property 189.7 181.1 CWIP 55.0 148.8 Total property, plant and equipment 3,485.9 3,259.3 Less accumulated amortization (1,244.3 ) (1,170.6 ) $ 2,241.6 $ 2,088.7
Schedule of Jointly Owned Utility Plants	(Millions of Dollars) Plant in Accumulated Depreciation CWIP Percent Owned Electric Transmission: La Crosse, Wis. to Madison, Wis. $ 175.4 $ 2.2 $ — 37 % CapX2020 Transmission 168.4 14.5 2.3 81 Total $ 343.8 $ 16.7 $ 2.3

Regulatory Assets and Liabili_2

Regulatory Assets and Liabilities (Tables)	12 Months Ended
	Dec. 31, 2018
Regulatory Assets and Liabilities Disclosure [Abstract]
Regulatory Assets	Components of regulatory assets: (Millions of Dollars) See Note(s) Remaining Dec. 31, 2018 Dec. 31, 2017 Regulatory Assets Current Noncurrent Current Noncurrent Environmental remediation costs 1, 10 Various $ 16.0 $ 135.2 $ 16.0 $ 136.1 Pension and retiree medical obligations 9 Various 5.5 85.1 5.7 87.5 Excess deferred taxes - TCJA 7 Various — 25.2 — 22.6 Recoverable deferred taxes on AFUDC recorded in plant Plant lives — 16.9 — 14.3 State commission adjustments Plant lives 0.8 16.8 0.7 15.9 Losses on reacquired debt Term of related debt 0.2 2.4 0.7 2.7 Other Various 0.1 3.9 — 3.1 Total regulatory assets $ 22.6 $ 285.5 $ 23.1 $ 282.2
Regulatory Liabilities	Components of regulatory liabilities: (Millions of Dollars) See Note(s) Remaining Dec. 31, 2018 Dec. 31, 2017 Regulatory Liabilities Current Noncurrent Current Noncurrent Deferred income tax adjustments and TCJA refunds (a) 7 Various $ 0.2 $ 238.3 $ — $ 236.1 Plant removal costs 1, 10 Plant lives — 157.7 — 146.4 Deferred electric production and natural gas costs Less than one year 13.4 — 13.9 — United States Department of Energy settlement Less than one year 6.2 — 5.3 — Other Various 1.1 4.1 1.5 4.3 Total regulatory liabilities $ 20.9 $ 400.1 $ 20.7 $ 386.8 (a) Includes the revaluation of recoverable/regulated plant ADIT and revaluation impact of non-plant ADIT due to the TCJA.

Borrowings and Other Financin_2

Borrowings and Other Financing Instruments Borrowings and Other Financing Instruments (Tables)	12 Months Ended
	Dec. 31, 2018
Debt Disclosure [Abstract]
Commercial Paper	Commercial paper outstanding for NSP-Wisconsin was as follows: Three Months Ended Dec. 31, 2018 Year Ended (Amounts in Millions, Except Interest Rates) 2018 2017 2016 Borrowing limit $ 150 $ 150 $ 150 $ 150 Amount outstanding at period end 51 51 11 60 Average amount outstanding 51 28 52 15 Maximum amount outstanding 103 103 129 64 Weighted average interest rate, computed on a daily basis 2.56 % 2.31 % 1.23 % 0.69 % Weighted average interest rate at period end 2.89 2.89 1.73 0.95
Schedule of Debt To Total Capitalization Ratio	Debt-to-Total Capitalization Ratio (a) Amount Facility May Be Increased (millions) Additional Periods For Which a One-Year Extension May Be Requested (b) 2018 2017 48 % 47 % N/A 1
Credit Facilities	Dec. 31, 2018 (in millions): Credit Facility (a) Drawn (b) Available $ 150 $ 51 $ 99 (a) This credit facility matures in June 2021 . (b) Includes outstanding commercial paper.
other short term debt [Table Text Block]	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, 2018 Dec. 31, 2017 Notes payable to affiliates $ 0.6 $ 0.5 Weighted average interest rate 2.89 % 1.73 %
Schedule of Capitalization	(Millions of Dollars) Maturity Range Interest Rate Range 2018 Interest Rate Range 2017 2018 2017 Mortgage bonds 2024-2048 3.3% - 6.38% 3.3% - 6.38% $ 800 $ 750 City of La Crosse resource recovery bond 2021 6.00 % 6.00 % 19 19 Other — 2 Unamortized discount (3 ) (3 ) Unamortized debt issuance cost (9 ) (7 ) Current maturities — (151 ) Total $ 807 $ 610
Schedule of Maturities of Long-term Debt	Maturities of long-term debt: (Millions of Dollars) 2019 $ — 2020 — 2021 19 2022 — 2023 —
Schedule of Long-Term Debt Issuances	2018 financings: Amount Financing Instrument Interest Rate Maturity Date 200 million First mortgage bonds 4.20 % Sept. 1, 2048 2017 financings: Amount Financing Instrument Interest Rate Maturity Date 100 million First mortgage bonds 3.75 % Dec. 1, 2047
Dividend Payment Restrictions	Equity to Total Capitalization Ratio Required Range Equity to Total Capitalization Ratio Actual Low High 2018 51.5 % N/A 51.8 % Unrestricted Retained Earnings Total Capitalization Limit on Total Capitalization $ 11.5 million $ 1.7 billion N/A (a) NSP-Wisconsin cannot pay annual dividends in excess of approximately $55 million if its average equity-to-total capitalization ratio falls below the commission authorized level.

Revenues Revenues (Tables)

Revenues Revenues (Tables)	12 Months Ended
	Dec. 31, 2018
Revenue from Contract with Customer [Abstract]
Disaggregation of Revenue [Table Text Block]	NSP-Wisconsin’s operating revenues (subsequent to adoption of the revised revenue guidance) consists of the following: Year Ended Dec. 31, 2018 (Millions of Dollars) Electric Natural Gas All Other Total Major revenue types Revenue from contracts with customers: Residential $ 255.2 $ 73.0 $ 0.1 $ 328.3 C&I 444.3 61.6 0.1 506.0 Other 6.1 — 1.1 7.2 Total retail 705.6 134.6 1.3 841.5 Interchange 157.9 — — 157.9 Other 3.6 4.6 — 8.2 Total revenue from contracts with customers 867.1 139.2 1.3 1,007.6 Alternative revenue and other 11.5 2.4 — 13.9 Total revenues $ 878.6 $ 141.6 $ 1.3 $ 1,021.5

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2018
Income Tax Disclosure [Abstract]
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. Statute of limitations applicable to Xcel Energy’s consolidated federal income tax returns expire as follows: Tax Year(s) Expiration 2009 - 2014 October 2019 2015 September 2019 2016 September 2020 2017 September 2021
Reconciliation of Unrecognized Tax Benefits	Unrecognized tax benefits - permanent vs. temporary: (Millions of Dollars) Dec. 31, 2018 Dec. 31, 2017 Unrecognized tax benefit — Permanent tax positions $ 2.0 $ 1.4 Unrecognized tax benefit — Temporary tax positions 0.8 1.0 Total unrecognized tax benefit $ 2.8 $ 2.4 Changes in unrecognized tax benefits: (Millions of Dollars) 2018 2017 2016 Balance at Jan. 1 $ 2.4 $ 5.3 $ 4.5 Additions based on tax positions related to the current year 0.2 0.4 0.5 Reductions based on tax positions related to the current year (0.1 ) (0.3 ) — Additions for tax positions of prior years 0.7 1.3 0.5 Reductions for tax positions of prior years (0.3 ) (4.3 ) (0.2 ) Settlements with taxing authorities (0.1 ) — — Balance at Dec. 31 $ 2.8 $ 2.4 $ 5.3
Tax Benefits Associated with NOL and Tax Credit Carryforwards	Unrecognized tax benefits were reduced by tax benefits associated with NOL and tax credit carryforwards: (Millions of Dollars) Dec. 31, 2018 Dec. 31, 2017 NOL and tax credit carryforwards $ (2.1 ) $ (1.9 )
NOL and Tax Credit Carryforwards	NOL amounts represent the tax loss that is carried forward and tax credits represent the deferred tax asset. NOL and tax credit carryforwards as of Dec. 31 were as follows: (Millions of Dollars) 2018 2017 Federal NOL carryforward $ — $ 57.8 Federal tax credit carryforwards 4.7 4.3 State NOL carryforward 2.5 5.4
Schedule of Effective Income Tax Rate Reconciliation	Total income tax expense from operations differs from the amount computed by applying the statutory federal income tax rate to income before income tax expense. Effective income tax rate for years ended Dec. 31: 2018 2017 (a) 2016 (a) Federal statutory rate 21.0 % 35.0 % 35.0 % State income tax on pretax income, net of federal tax effect 6.2 % 5.1 % 5.1 % Increases (decreases) in tax from: Regulatory differences - ARAM (b) (4.3 ) (0.1 ) (0.2 ) Regulatory differences - deferral of ARAM (c) 4.1 — — Regulatory differences - other utility plant items (1.3 ) (1.7 ) (0.6 ) Tax credits recognized, net of federal income tax expense (0.8 ) (1.0 ) (0.7 ) Adjustments attributable to tax returns (0.6 ) (2.3 ) (0.3 ) Change in unrecognized tax benefits 0.4 0.8 0.1 Tax reform — — — Other, net 0.1 — (0.1 ) Effective income tax rate 24.8 % 35.8 % 38.3 % (a) Prior periods have been reclassified to conform to current year presentation. (b) ARAM is a method to flow back excess deferred taxes to customers. (c) ARAM has been deferred when regulatory treatment has not been established. As Xcel Energy received direction from its regulatory commissions regarding the return of excess deferred taxes to customers, the ARAM deferral was reversed. This resulted in a reduction to tax expense with a corresponding reduction to revenue.
Schedule of Components of Income Tax Expense (Benefit)	Components of income tax expense for years ended Dec. 31: (Millions of Dollars) 2018 2017 2016 Current federal tax expense $ 7.6 $ 2.8 $ 5.4 Current state tax expense 1.7 — 0.1 Current change in unrecognized tax expense (benefit) 0.2 (3.7 ) 0.5 Deferred federal tax expense 15.6 32.9 29.6 Deferred state tax expense 7.4 8.0 8.2 Deferred change in unrecognized tax expense (benefit) 0.3 4.7 (0.4 ) Deferred ITCs (0.5 ) (0.5 ) (0.5 ) Total income tax expense $ 32.3 $ 44.2 $ 42.9 Components of deferred income tax expense as of Dec. 31: (Millions of Dollars) 2018 2017 2016 Deferred tax expense (benefit) excluding items below $ 24.0 $ (173.9 ) $ 39.5 Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities (0.7 ) 219.5 (2.1 ) Deferred tax expense $ 23.3 $ 45.6 $ 37.4
Schedule of Deferred Tax Assets and Liabilities	Components of net deferred tax liability as of Dec. 31: (Millions of Dollars) 2018 2017 Deferred tax liabilities: Difference between book and tax bases of property $ 281.1 $ 269.5 Regulatory assets 55.4 58.4 Pension expense 13.9 14.2 Other 6.9 7.0 Total deferred tax liabilities $ 357.3 $ 349.1 Deferred tax assets: Regulatory liabilities $ 53.4 $ 55.8 NOL carryforward 0.4 12.6 Environmental remediation 7.8 8.1 Tax credit carryforward 4.7 4.6 Other employee benefits 4.1 3.9 Deferred ITCs 3.0 3.2 Other 3.2 4.2 Total deferred tax assets $ 76.6 $ 92.4 Net deferred tax liability $ 280.7 $ 256.7

Fair Value of Financial Asset_2

Fair Value of Financial Assets and Liabilities (Tables)	12 Months Ended
	Dec. 31, 2018
Fair Value Disclosures [Abstract]
Gross Notional Amounts of Commodity Forwards and Options	Gross notional amounts of commodity options at Dec. 31: (Amounts in Millions) (a) (b) 2018 2017 MMBtu of natural gas 1.2 — (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	Qualifying Cash Flow Hedges — Financial 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: (Millions of Dollars) 2018 2017 2016 Accumulated other comprehensive loss related to cash flow hedges at Jan. 1 $ (0.1 ) $ (0.1 ) $ (0.2 ) After-tax net realized losses on derivative transactions reclassified into earnings 0.1 — 0.1 Accumulated other comprehensive loss related to cash flow hedges at Dec. 31 $ — $ (0.1 ) $ (0.1 )
Derivative Assets and Liabilities Measured at Fair Value on a Recurring Basis by Hierarchy Level	The following table presents for each of the fair value hierarchy levels, NSP-Wisconsin’s derivative assets measured at fair value on a recurring basis at Dec. 31, 2018 : Dec. 31, 2018 Fair Value Fair Value Total Netting (a) (Millions of Dollars) Level 1 Level 2 Level 3 Total (b) Current derivative assets Natural gas commodity $ — $ 0.2 $ — $ 0.2 $ — $ 0.2 (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, 2018. The counterparty netting excludes 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 $3.3 million at Dec. 31, 2018 in the consolidated balance sheet.
Carrying Amount and Fair Value of Long-term Debt	As of Dec. 31, other financial instruments for which the carrying amount did not equal fair value: 2018 2017 (Millions of Dollars) Carrying Amount Fair Value Carrying Amount Fair Value Long-term debt, including current portion $ 807.5 $ 850.4 $ 761.2 $ 856.1

Benefit Plans and Other Postr_2

Benefit Plans and Other Postretirement Benefits (Tables)	12 Months Ended
	Dec. 31, 2018
Benefit Plans and Other Postretirement Benefits [Abstract]
Funded Status of Plans	Pension Benefits Postretirement Benefits (Millions of Dollars) 2018 2017 2018 2017 Change in Benefit Obligation: Obligation at Jan. 1 $ 156.8 $ 157.5 $ 16.4 $ 15.0 Service cost 4.8 4.6 — — Interest cost 5.4 6.2 0.6 0.6 Plan participants’ contributions — — — 0.1 Plan amendments — (0.7 ) — — Actuarial (gain) loss (13.4 ) 6.5 (3.3 ) 2.1 Benefit payments (a) (13.8 ) (17.3 ) (0.9 ) (1.4 ) Obligation at Dec. 31 $ 139.8 $ 156.8 $ 12.8 $ 16.4 Change in Fair Value of Plan Assets: Fair value of plan assets at Jan. 1 $ 124.9 $ 119.0 $ 1.1 $ 0.5 Actual return on plan assets (11.1 ) 13.9 — — Plan participants’ contributions — — — 0.1 Employer contributions 9.5 9.3 0.2 1.9 Benefit payments (13.8 ) (17.3 ) (0.9 ) (1.4 ) Fair value of plan assets at Dec. 31 $ 109.5 $ 124.9 $ 0.4 $ 1.1 Funded status of plans at Dec. 31 $ (30.3 ) $ (31.9 ) $ (12.4 ) $ (15.3 ) Amounts recognized in the Consolidated Balance Sheet at Dec. 31: Current liabilities $ — $ — $ (0.8 ) $ (0.3 ) Noncurrent liabilities (30.3 ) (31.9 ) (11.6 ) (15.0 ) Net amounts recognized $ (30.3 ) $ (31.9 ) $ (12.4 ) $ (15.3 ) Significant Assumptions Used to Measure Benefit Obligations: Discount rate for year-end valuation 4.31 % 3.63 % 4.32 % 3.62 % Expected average long-term increase in compensation level 3.75 3.75 N/A N/A Mortality table RP-2014 RP-2014 RP-2014 RP-2014 Health care costs trend rate — initial: Pre-65 N/A N/A 6.5 % 7.0 % Health care costs trend rate — initial: Post-65 N/A N/A 5.3 % 5.5 % Ultimate trend assumption — initial: Pre-65 N/A N/A 4.5 % 4.5 % Ultimate trend assumption — initial: Post-65 N/A N/A 4.5 % 4.5 % Years until ultimate trend is reached N/A N/A 4 5
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost	Pension Benefits Postretirement Benefits (Millions of Dollars) 2018 2017 2018 2017 Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost: Net loss $ 74.3 $ 80.4 $ 6.8 $ 10.6 Prior service credit (0.3 ) (0.3 ) (1.4 ) (1.8 ) Total $ 74.0 $ 80.1 $ 5.4 $ 8.8 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 $ 5.3 $ 5.5 $ 0.2 $ 0.1 Noncurrent regulatory assets 68.7 74.6 5.2 8.7 Total $ 74.0 $ 80.1 $ 5.4 $ 8.8
Components of Net Periodic Benefit Costs	Pension Benefits Postretirement Benefits (Millions of Dollars) 2018 2017 2016 2018 2017 2016 Service cost $ 4.8 $ 4.6 $ 4.4 $ — $ — $ — Interest cost 5.4 6.2 6.9 0.6 0.6 0.7 Expected return on plan assets (9.0 ) (9.2 ) (9.2 ) (0.1 ) — — Amortization of prior service credit — 0.1 0.1 (0.4 ) (0.4 ) (0.4 ) Amortization of net loss 5.7 5.9 5.4 0.6 0.4 0.3 Settlement charge (a) 7.2 7.1 — — — — Net periodic pension cost (credit) $ 14.1 $ 14.7 $ 7.6 $ 0.7 $ 0.6 $ 0.6 Costs not recognized due to effects of regulation (3.4 ) (4.2 ) — — — — Net benefit cost (credit) recognized for financial reporting $ 10.7 $ 10.5 $ 7.6 $ 0.7 $ 0.6 $ 0.6 Significant Assumptions Used to Measure Costs: Discount rate 3.63 % 4.13 % 4.66 % 3.62 % 4.13 % 4.65 % Expected average long-term increase in compensation level 3.75 3.75 4.00 — — — Expected average long-term rate of return on assets 7.10 7.10 7.10 5.30 5.80 5.80 (a) A settlement charge is required when the amount of all 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 2018 and 2017, as a result of lump-sum distributions during the 2018 and 2017 plan years, NSP-Wisconsin recorded a total pension settlement charge of $7.2 million in 2018 and $7.1 million in 2017, a total of $2 million and $2 million of that amount was recorded in the income statement in 2018 and 2017.
Target Asset Allocations and Plan Assets Measured at Fair Value	Target asset allocations: Pension Benefits Postretirement Benefits 2018 2017 2018 2017 Domestic and international equity securities 37 % 38 % 18 % 24 % Long-duration fixed income and interest rate swap securities 28 23 — — Short-to-intermediate fixed income securities 18 21 70 60 Alternative investments 15 16 8 9 Cash 2 2 4 7 Total 100 % 100 % 100 % 100 % Plan Assets The following presents, for each of the fair value hierarchy levels, NSP-Wisconsin’s pension plan assets measured at fair value: Dec. 31, 2018 (a) Dec. 31, 2017 (a) (Thousands of Dollars) Level 1 Level 2 Level 3 Measured at NAV Total Level 1 Level 2 Level 3 Measured at NAV Total Cash equivalents $ 4.9 $ — $ — $ — $ 4.9 $ 8.1 $ — $ — $ — $ 8.1 Commingled funds: 37.1 — — 41.8 78.9 43.2 — — 45.9 89.1 Debt securities: — 22.2 — — 22.2 — 24.1 — — 24.1 Equity securities: 4.6 — — — 4.6 4.9 — — — 4.9 Other — 0.2 — (1.3 ) (1.1 ) (1.3 ) 0.1 — — (1.2 ) Total $ 46.6 $ 22.4 $ — $ 40.5 $ 109.5 $ 54.9 $ 24.2 $ — $ 45.8 $ 124.9 (a) See Note 8 for further information on fair value measurement inputs and methods. The following presents, for each of the fair value hierarchy levels, NSP-Wisconsin’s postretirement benefit plan assets that were measured at fair value: Dec. 31, 2018 (a) Dec. 31, 2017 (a) (Millions of Dollars) Level 1 Level 2 Level 3 Measured at NAV Total Level 1 Level 2 Level 3 Measured at NAV Total Cash equivalents $ — $ — $ — $ — $ — $ 0.1 $ — $ — $ — $ 0.1 Insurance contracts — 0.1 — — 0.1 — 0.1 — — 0.1 Commingled funds 0.1 — — — 0.1 0.3 — — — 0.3 Debt securities — 0.2 — — 0.2 — 0.5 — — 0.5 Equity securities — — — — — 0.1 — — — 0.1 Total $ 0.1 $ 0.3 $ — $ — $ 0.4 $ 0.5 $ 0.6 $ — $ — $ 1.1 (a) See Note 8 for further information on fair value measurement inputs and methods.
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 2019 $ 14.6 $ 1.2 $ — $ 1.2 2020 10.9 1.1 — 1.1 2021 10.9 1.1 — 1.1 2022 10.8 1.0 — 1.0 2023 11.1 1.0 — 1.0 2024-2028 55.5 4.2 — 4.2

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2018
Commitments and Contingencies Disclosure [Abstract]
Total expense for energy and capacity payments table text block [Table Text Block]	Total expenses under operating lease obligations for NSP-Wisconsin for the year ended Dec. 31: (Millions of Dollars) 2018 2017 2016 Total expense $ 1.3 $ 1.2 $ 1.2
Estimated Minimum Purchases Under Fuel Contracts	(Millions of Dollars) Coal Natural gas Natural gas 2019 $ 6.1 $ 9.9 $ 13.4 2020 2.3 0.3 11.8 2021 0.6 0.4 11.3 2022 0.7 0.2 9.7 2023 0.7 — 7.9 Thereafter — — 24.3 Total (a) $ 10.4 $ 10.8 $ 78.4
Future Commitments Under Operating Leases	(Millions of Dollars) 2019 $ 1.0 2020 0.9 2021 0.8 2022 0.8 2023 0.8 Thereafter 3.8 Total $ 8.1
Low-income Housing Limited Partnerships	(Millions of Dollars) Dec. 31, 2018 Dec. 31, 2017 Current assets $ 0.3 $ 0.4 Property, plant and equipment, net 0.9 1.9 Other noncurrent assets 0.1 0.1 Total assets $ 1.3 $ 2.4 Current liabilities $ — $ 1.2 Mortgages and other long-term debt payable 0.5 0.5 Other noncurrent liabilities — 0.1 Total liabilities $ 0.5 $ 1.8
Guarantee Issued and Outstanding	The following table presents the guarantee issued and outstanding for NSP-Wisconsin: (Millions of Dollars) Guarantor Guarantee Current Triggering Guarantee of customer loans for the Farm Rewiring Program (a) NSP-Wisconsin $ 1.0 $ — (b) (a) The term of this guarantee expires in 2020 , which is the final scheduled repayment date for the loans. As of Dec. 31, 2018, no claims had been made by the lender. (b) The debtor becomes the subject of bankruptcy or other insolvency proceedings.
Asset Retirement Obligations	NSP-Wisconsin’s AROs were as follows: Dec. 31, 2018 (Millions of Dollars) Jan. 1, 2018 Accretion Cash Flow Revisions (a) Dec. 31, 2018 (b) Electric Distribution $ — $ — $ 4.6 $ 4.6 Steam production 3.7 0.1 — 3.8 Miscellaneous 0.4 — — 0.4 Natural gas Distribution 10.3 0.4 (1.6 ) 9.1 Total liability (c) $ 14.4 $ 0.5 $ 3.0 $ 17.9 (a) In 2018, AROs were revised for changes in timing and estimates of cash flows. Changes in gas distribution AROs were mainly related to increased gas line mileage and number of services, which were more than offset by increased discount rates. Changes in electric distribution AROs primarily related to increased labor costs. (b) There were no ARO amounts incurred or settled in 2018. (c) Included in other long-term liabilities balance in the consolidated balance sheet. Dec. 31, 2017 (Millions of Dollars) Jan. 1, 2017 Amounts Incurred (a) Accretion Cash Flow Revisions (b) Dec. 31, 2017 (c) Electric Steam production $ 2.7 $ 1.0 $ — $ — $ 3.7 Miscellaneous 0.4 — — — 0.4 Natural gas Distribution 8.3 — 0.3 1.7 10.3 Total liability (d) $ 11.4 $ 1.0 $ 0.3 $ 1.7 $ 14.4 (a) Amounts incurred related to asbestos at the French Island plant. (b) Changes in gas distribution AROs were primarily related to increased labor costs. (c) There were no ARO amounts settled in 2017. (d) Included in other long-term liabilities balance in the consolidated balance sheet.

Other Comprehensive Income (Tab

Other Comprehensive Income (Tables)	12 Months Ended
	Dec. 31, 2018
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, 2018 and 2017 : Gains and Losses on Cash Flow Hedges (Millions of Dollars) 2018 2017 Accumulated other comprehensive loss at Jan. 1 $ (0.1 ) $ (0.1 ) Losses reclassified from net accumulated other comprehensive loss (net of taxes of $0 and $0), respectively (a) 0.1 — Net current period other comprehensive income 0.1 — Accumulated other comprehensive loss at Dec. 31 $ — $ (0.1 )
Reclassifications out of Accumulated Other Comprehensive Loss	(a) Included in interest charges.

Segments and Related Informat_2

Segments and Related Information (Tables)	12 Months Ended
	Dec. 31, 2018
Segment Reporting [Abstract]
Results from Operations by Reportable Segment	(Millions of Dollars) 2018 2017 2016 Regulated Electric Operating revenues (a) $ 878.6 $ 881.9 $ 849.9 Intersegment revenues 0.4 0.5 0.4 Total operating revenue $ 879.0 $ 882.4 $ 850.3 Depreciation and amortization 97.8 88.9 81.3 Interest charges and financing costs 31.8 29.4 29.7 Income tax expense 28.4 38.9 40.5 Net income 85.5 70.9 65.0 Regulated Natural Gas Operating revenues (a) $ 141.6 $ 122.4 $ 106.2 Intersegment revenues 0.4 0.3 0.5 Total operating revenue $ 142.0 $ 122.7 $ 106.7 Depreciation and amortization 28.1 22.1 16.8 Interest charges and financing costs 3.3 2.8 2.9 Income tax expense 4.5 4.0 2.4 Net income 12.5 7.8 4.5 All Other Operating revenues (a) $ 1.3 $ 1.2 $ 1.1 Depreciation and amortization 0.2 0.2 0.2 Interest charges and financing costs 0.1 — — Income tax (benefit) (0.6 ) 1.3 — Net (loss) — 0.7 (0.4 ) Consolidated Total Total operating revenue $ 1,022.3 $ 1,006.3 $ 958.1 Reconciling eliminations (0.8 ) (0.8 ) (0.9 ) Consolidated total revenue $ 1,021.5 $ 1,005.5 $ 957.2 Depreciation and amortization 126.1 111.2 98.3 Interest charges and financing costs 35.2 32.2 32.6 Income tax expense 32.3 44.2 42.9 Net income 98.0 79.4 69.1 (a) Operating revenues include $157.9 million , $177.2 million and $170.5 million of intercompany revenue for the years ended Dec. 31, 2018, 2017 and 2016, respectively. See Note 13 for further information.

Related Party Transactions (Tab

Related Party Transactions (Tables)	12 Months Ended
	Dec. 31, 2018
Related Party Transactions [Abstract]
Related Party Transactions	Significant affiliate transactions among the companies and related parties including billings under the Interchange Agreement for the years ended Dec. 31: (Millions of Dollars) 2018 2017 2016 Operating revenues: Electric $ 157.9 $ 177.2 $ 170.4 Operating expenses: Purchased power 410.9 421.6 413.6 Transmission expense 62.8 68.6 61.9 Other operating expenses — paid to Xcel Energy Services Inc. 86.9 92.7 106.5 Accounts receivable and payable with affiliates at Dec. 31 were: 2018 2017 (Millions of Dollars) Accounts Accounts Accounts Accounts NSP-Minnesota $ — $ 11.0 $ — $ 17.8 PSCo 0.2 — — — Other subsidiaries of Xcel Energy Inc. 14.9 9.0 3.4 11.8 $ 15.1 $ 20.0 $ 3.4 $ 29.6

Summarized Quarterly Financia_2

Summarized Quarterly Financial Data (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2018
Quarterly Financial Information Disclosure [Abstract]
Summarized Quarterly Financial Data (Unaudited)	Quarter Ended (Millions of Dollars) March 31, 2018 June 30, 2018 Sept. 30, 2018 Dec. 31, 2018 Operating revenues $ 273.1 $ 231.8 $ 256.0 $ 260.6 Operating income 49.0 27.5 48.0 34.9 Net income 31.4 15.2 31.0 20.4 Quarter Ended (Millions of Dollars) March 31, 2017 June 30, 2017 Sept. 30, 2017 Dec. 31, 2017 Operating revenues $ 264.9 $ 230.1 $ 247.5 $ 263.0 Operating income (a) 43.5 29.7 39.2 40.2 Net income 22.4 14.3 22.3 20.4 (a) In 2018, NSP-Wisconsin implemented ASU No. 2017-07 related to net periodic benefit cost, which resulted in retrospective reclassification of pension costs from O&M expense to other income.

Summary of Significant Accoun_3

Summary of Significant Accounting Policies (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Property, Plant and Equipment [Abstract]
Depreciation expense expressed as a percentage of average depreciable property	3.50%	3.40%	3.30%
Operating revenues
Minimum annual tolerance band percentage for future rate recovery or refund of fuel costs	2.00%
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	three months
Accounts, Notes, Loans and Financing Receivable, Classified [Abstract]
Allowance for Doubtful Accounts Receivable, Current	$ 5.6	$ 4.9
Alternative Revenue Programs [Abstract]
Maximum number of months following end of annual period in which revenues are earned to be included in incentive programs	24 months
Percentage of Average Annual Operating Revenues	1.20%
Number of Years Annual Operating Revenues are Averaged	3 years
Public Utilities, Inventory [Line Items]
Public Utilities, Inventory	$ 17.1	17.8
Materials and supplies
Public Utilities, Inventory [Line Items]
Public Utilities, Inventory	6.7	6.9
Fuel
Public Utilities, Inventory [Line Items]
Public Utilities, Inventory	3.8	3.9
Natural gas
Public Utilities, Inventory [Line Items]
Public Utilities, Inventory	$ 6.6	$ 7

Accounting Pronouncements Adopt

Accounting Pronouncements Adoption of New Accounting Pronouncements (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Other Expense | Accounting Standards Update 2017-07
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit)	$ 4.3	$ 3

Property Plant and Equipment _3

Property Plant and Equipment Property Plant and Equipment (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	$ 3,485.9	$ 3,259.3
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment	1,244.3	1,170.6
Property, Plant and Equipment, Net	2,241.6	2,088.7
Electric plant
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	2,895.5	2,602.7
Natural gas plant
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	345.7	326.7
Common and other property
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	189.7	181.1
CWIP
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Gross	$ 55	$ 148.8

Property Plant and Equipment Jo

Property Plant and Equipment Joint Ownership (Details) $ in Millions	12 Months Ended
	Dec. 31, 2018USD ($)Counterparty
Jointly Owned Utility Plant Interests [Line Items]
Number of companies covered by FERC approved Interchange Agreement | Counterparty	2
NSP-Wisconsin
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	$ 343.8
Accumulated Depreciation	16.7
CWIP	2.3
NSP-Wisconsin | Electric Transmission | CapX2020 Transmission
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	168.4
Accumulated Depreciation	14.5
CWIP	$ 2.3
Ownership percentage (in hundredths)	81.00%
NSP-Wisconsin | Electric Transmission | La Crosse, Wis. to Madison, Wis.
Jointly Owned Utility Plant Interests [Line Items]
Plant in Service	$ 175.4
Accumulated Depreciation	2.2
CWIP	$ 0
Ownership percentage (in hundredths)	37.00%

Regulatory Assets and Liabili_3

Regulatory Assets and Liabilities, Regulatory Assets (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Regulatory Assets [Line Items]
Regulatory Asset, Current	$ 22.6	$ 23.1
Regulatory Asset, Noncurrent	285.5	282.2
Environmental Remediation Costs
Regulatory Assets [Line Items]
Regulatory Asset, Current	16	16
Regulatory Asset, Noncurrent	$ 135.2	136.1
Regulatory asset, remaining amortization period	Various
Pension and Retiree Medical Obligations
Regulatory Assets [Line Items]
Regulatory Asset, Current	$ 5.5	5.7
Regulatory Asset, Noncurrent	$ 85.1	87.5
Regulatory asset, remaining amortization period	Various
Excess deferred taxes - TCJA
Regulatory Assets [Line Items]
Regulatory Asset, Current	$ 0	0
Regulatory Asset, Noncurrent	$ 25.2	22.6
Regulatory asset, remaining amortization period	Various
Recoverable Deferred Taxes on AFUDC Recorded in Plant
Regulatory Assets [Line Items]
Regulatory Asset, Current	$ 0	0
Regulatory Asset, Noncurrent	$ 16.9	14.3
Regulatory asset, remaining amortization period	Plant lives
State Commission Adjustments
Regulatory Assets [Line Items]
Regulatory Asset, Current	$ 0.8	0.7
Regulatory Asset, Noncurrent	$ 16.8	15.9
Regulatory asset, remaining amortization period	Plant lives
Losses on Reacquired Debt
Regulatory Assets [Line Items]
Regulatory Asset, Current	$ 0.2	0.7
Regulatory Asset, Noncurrent	$ 2.4	2.7
Regulatory asset, remaining amortization period	Term of related debt
Other Regulatory Assets
Regulatory Assets [Line Items]
Regulatory Asset, Current	$ 0.1	0
Regulatory Asset, Noncurrent	$ 3.9	$ 3.1
Regulatory asset, remaining amortization period	Various

Regulatory Assets and Liabili_4

Regulatory Assets and Liabilities, Regulatory Liabilities (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2018	Dec. 31, 2017
Regulatory Liabilities [Line Items]
Regulatory Liability, Current		$ 20.9	$ 20.7
Regulatory Liability, Noncurrent		400.1	386.8
Deferred Income Tax Adjustments and TCJA Refunds
Regulatory Liabilities [Line Items]
Regulatory Liability, Current	[1]	0.2	0
Regulatory Liability, Noncurrent	[1]	$ 238.3	236.1
Regulatory liability, remaining amortization period		Various
Plant Removal Costs
Regulatory Liabilities [Line Items]
Regulatory Liability, Current		$ 0	0
Regulatory Liability, Noncurrent		$ 157.7	146.4
Regulatory liability, remaining amortization period		Plant lives
Deferred Electric Production And Natural Gas Costs
Regulatory Liabilities [Line Items]
Regulatory Liability, Current		$ 13.4	13.9
Regulatory Liability, Noncurrent		$ 0	0
Regulatory liability remaining amortization period, maximum		Less than one year
DOE Settlement
Regulatory Liabilities [Line Items]
Regulatory Liability, Current		$ 6.2	5.3
Regulatory Liability, Noncurrent		$ 0	0
Regulatory liability remaining amortization period, maximum		Less than one year
Other Regulatory Liabilities
Regulatory Liabilities [Line Items]
Regulatory Liability, Current		$ 1.1	1.5
Regulatory Liability, Noncurrent		$ 4.1	$ 4.3
Regulatory liability, remaining amortization period		Various
[1]	Includes the revaluation of recoverable/regulated plant ADIT and revaluation impact of non-plant ADIT due to the TCJA.

Borrowings and Other Financin_3

Borrowings and Other Financing Instruments Borrowings and Other Financing Instruments, Commercial Paper (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Short-term Debt [Line Items]
Amount outstanding at period end	$ 51	$ 51	$ 11
Notes payable to affiliates	0.6	0.6	0.5
payable to affiliates [Member]
Short-term Debt [Line Items]
Notes payable to affiliates	$ 0.6	$ 0.6	$ 0.5
Weighted average interest rate at period end (percentage)	2.89%	2.89%	1.73%
Commercial Paper [Member]
Short-term Debt [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	$ 150	$ 150	$ 150	$ 150
Amount outstanding at period end	51	51	11	60
Average amount outstanding	51	28	52	15
Maximum amount outstanding	$ 103	$ 103	$ 129	$ 64
Weighted average interest rate, computed on a daily basis (percentage)	2.56%	2.31%	1.23%	0.69%
Weighted average interest rate at period end (percentage)	2.89%	2.89%	1.73%	0.95%

Borrowings and Other Financin_4

Borrowings and Other Financing Instruments Borrowings and Other Financing Instruments, Letters of Credit (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Line of Credit Facility [Line Items]
Amount outstanding at period end	$ 51	$ 11
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]
Line of Credit Facility, Expiration Period	1 year

Borrowings and Other Financin_5

Borrowings and Other Financing Instruments Borrowings and Other Financing Instruments, Credit Facilities (Details) - Credit Facilities		12 Months Ended
		Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)
Line of Credit Facility [Line Items]
Line Of Credit Facility Debt To Total Capitalization Ratio (as a percent)		48.00%	47.00%
Number Of Additional Periods Revolving Termination Date Can Be Extended Subject To Majority Bank Group Approval		1
Term Of Each Additional Period Revolving Termination Date Can Be Extended Subject To Majority Bank Group Approval		1
Line Of Credit Facility Maximum Debt To Total Capitalization Ratio Allowed		65.00%
Line Of Credit Facility Minimum Threshhold Percentage Of Subsidiary Assets To Consolidated Assets Required To Initiate Cross Default Provisions		15.00%
Line of Credit Facility, Minimum Amount of Indebtedness in Default to Initiate Cross Default Provisions		$ 75,000,000
Credit Facility	[1]	150,000,000
Drawn	[2]	51,000,000
Available		$ 99,000,000
Debt Instrument, Maturity Date		Jun. 30, 2021
Long-term Line of Credit		$ 0	$ 0
[1]	This credit facility matures in June 2021.
[2]	Includes outstanding commercial paper.

Borrowings and Other Financin_6

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, 2018	Dec. 31, 2017
Long-Term Borrowings and Other Financing Instruments
Unamortized discount	$ (3)	$ (3)
Unamortized debt expense	(9)	(7)
Less current maturities	0	(151)
Long-term debt, noncurrent	807	610
2,019	0
2,020	0
2,021	19
2,022	0
2,023	0
First Mortgage Bonds
Long-Term Borrowings and Other Financing Instruments
Long-term Debt, Gross	$ 800	750
Debt Instrument, Maturity Date Range, Start	Jun. 15, 2024
Debt Instrument, Maturity Date Range, End	Sep. 1, 2048
City of La Crosse Resource Recovery Bond
Long-Term Borrowings and Other Financing Instruments
Long-term Debt, Gross	$ 19	$ 19
Debt Instrument, Interest Rate, Stated Percentage	6.00%	6.00%
Debt Instrument, Maturity Date	Nov. 1, 2021
Other
Long-Term Borrowings and Other Financing Instruments
Long-term Debt, Gross	$ 0	$ 2
Series Due December 1, 2047 [Member] | First Mortgage Bonds
Long-Term Borrowings and Other Financing Instruments
Debt Instrument, Interest Rate, Stated Percentage		3.75%
Debt Instrument, Face Amount		$ 100
Debt Instrument, Maturity Date		Dec. 1, 2047
Series Due December 1, 2048 [Member] | First Mortgage Bonds
Long-Term Borrowings and Other Financing Instruments
Debt Instrument, Interest Rate, Stated Percentage	4.20%
Debt Instrument, Face Amount	$ 200
Debt Instrument, Maturity Date	Sep. 1, 2048
Minimum | First Mortgage Bonds
Long-Term Borrowings and Other Financing Instruments
Debt Instrument, Interest Rate, Stated Percentage	3.30%	3.30%
Maximum | First Mortgage Bonds
Long-Term Borrowings and Other Financing Instruments
Debt Instrument, Interest Rate, Stated Percentage	6.375%	6.375%

Borrowings and Other Financin_7

Borrowings and Other Financing Instruments Borrowings and Other Financing Instruments, Deferred Financing Costs (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Deferred Financing Costs [Abstract]
Deferred Finance Costs, Noncurrent, Net	$ 9	$ 7

Borrowings and Other Financin_8

Borrowings and Other Financing Instruments Borrowings and Other Financing Instruments, Dividend and Other Capital-Related Restrictions (Details) $ in Millions	Dec. 31, 2018USD ($)
Dividend and Other Capital-Related Restrictions [Abstract]
Minimum calendar year average equity to total capitalization ratio authorized by state commission	51.50%
Equity to total capitalization ratio	51.80%
Unrestricted Retained Earnings Per State Regulatory Commissions Dividend Restrictions	$ 11.5
Capitalization, Short term debt, long term debt and equity	1,700
Maximum annual dividends that can be paid if equity capitalization ratio condition is not met	$ 55

Revenues (Details)

Revenues (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Disaggregation of Revenue [Line Items]
Operating revenues	$ 260.6	$ 256	$ 231.8	$ 273.1	$ 263	$ 247.5	$ 230.1	$ 264.9	$ 1,021.5	$ 1,005.5	$ 957.2
Total revenue from contracts with customers
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									1,007.6
Retail
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									841.5
Retail | Residential
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									328.3
Retail | Commercial and industrial (C&I)
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									506
Retail | Other
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									7.2
Interchange
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									157.9
Other
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									8.2
Alternative and Other [Member]
Disaggregation of Revenue [Line Items]
Operating revenues									13.9
Regulated Electric | Total revenue from contracts with customers
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									867.1
Regulated Electric | Retail
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									705.6
Regulated Electric | Retail | Residential
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									255.2
Regulated Electric | Retail | Commercial and industrial (C&I)
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									444.3
Regulated Electric | Retail | Other
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									6.1
Regulated Electric | Interchange
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									157.9
Regulated Electric | Other
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									3.6
Regulated Electric | Alternative and Other [Member]
Disaggregation of Revenue [Line Items]
Operating revenues									11.5
Regulated Natural Gas | Total revenue from contracts with customers
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									139.2
Regulated Natural Gas | Retail
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									134.6
Regulated Natural Gas | Retail | Residential
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									73
Regulated Natural Gas | Retail | Commercial and industrial (C&I)
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									61.6
Regulated Natural Gas | Retail | Other
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0
Regulated Natural Gas | Interchange
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0
Regulated Natural Gas | Other
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									4.6
Regulated Natural Gas | Alternative and Other [Member]
Disaggregation of Revenue [Line Items]
Operating revenues									2.4
All Other | Total revenue from contracts with customers
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									1.3
All Other | Retail
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									1.3
All Other | Retail | Residential
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0.1
All Other | Retail | Commercial and industrial (C&I)
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0.1
All Other | Retail | Other
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									1.1
All Other | Interchange
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0
All Other | Other
Disaggregation of Revenue [Line Items]
Total revenue from contracts with customers									0
All Other | Alternative and Other [Member]
Disaggregation of Revenue [Line Items]
Operating revenues									0
Operating Segments
Disaggregation of Revenue [Line Items]
Operating revenues									1,021.5
Operating Segments | Regulated Electric
Disaggregation of Revenue [Line Items]
Operating revenues									878.6
Operating Segments | Regulated Natural Gas
Disaggregation of Revenue [Line Items]
Operating revenues									141.6
Operating Segments | All Other
Disaggregation of Revenue [Line Items]
Operating revenues									$ 1.3

Income Taxes (Details)

Income Taxes (Details) - USD ($)		1 Months Ended	3 Months Ended				12 Months Ended
		Dec. 31, 2017	Dec. 31, 2018	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2015	Dec. 31, 2018	Dec. 31, 2017		Dec. 31, 2016		Dec. 31, 2012	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Federal Tax Reform [Abstract]
Tax Cuts and Jobs Act of 2017, Corporate Federal Tax Rate		21.00%					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
Unrecognized Tax Benefits [Abstract]
Unrecognized Tax Benefits - Permanent tax positions													$ 2,000,000	$ 1,400,000
Unrecognized tax benefit — Temporary tax positions													800,000	1,000,000
Total unrecognized tax benefit		$ 2,400,000	$ 2,800,000				$ 2,400,000	5,300,000		$ 4,500,000			2,800,000	2,400,000	$ 5,300,000
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Balance at Jan. 1							2,400,000	5,300,000		4,500,000
Unrecognized Tax Benefits, Increase Resulting from Current Period Tax Positions							200,000	400,000		500,000
Unrecognized Tax Benefits, Decrease Resulting from Current Period Tax Positions							(100,000)	(300,000)		0
Unrecognized Tax Benefits Increases Resulting From Prior Period Tax Positions							700,000	1,300,000		500,000
Unrecognized Tax Benefits Decreases Resulting From Prior Period Tax Positions							(300,000)	(4,300,000)		(200,000)
Unrecognized Tax Benefits, Decrease Resulting from Settlements with Taxing Authorities							(100,000)	0		0
Balance at Dec. 31		$ 2,400,000	$ 2,800,000				$ 2,800,000	$ 2,400,000		$ 5,300,000
Tax Benefits Associated With NOL And Tax Credit Carryforwards [Abstract]
NOL and tax credit carryforwards													(2,100,000)	(1,900,000)
Net Deferred Tax Liability associated with the Unrecognized Tax Benefit Amounts and Related NOLs and Tax Credit Carryforwards													(1,100,000)	(800,000)
Decrease in Unrecognized Tax Benefits is Reasonably Possible													2,200,000
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							21.00%	35.00%	[1]	35.00%	[1]
Effective Income Tax Rate Reconciliation, State and Local Income Taxes, Percent							6.20%	5.10%	[1]	5.10%	[1]
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Percent	[2]						(4.30%)	(0.10%)	[1]	(0.20%)	[1]
Effective Income Tax Rate Reconciliation, Tax Cuts and Jobs Act of 2017, Change in Tax Rate, Percent	[3]						4.10%	0.00%	[1]	0.00%	[1]
Effective Income Tax Rate Reconciliation, Other Regulatory Items, Percent							(1.30%)	(1.70%)	[1]	(0.60%)	[1]
Effective Income Tax Rate Reconciliation Regulatory Differences Utility Plant Items							(0.80%)	(1.00%)	[1]	(0.70%)	[1]
Effective Income Tax Reconciliation, Adjustments Attributable to Tax Returns, Percent							(0.60%)	(2.30%)	[1]	(0.30%)	[1]
Effective Income Tax Rate Reconciliation Change In Unrecognized Tax Benefits, Percent							0.40%	0.80%	[1]	0.10%	[1]
Effective Income Tax Rate Reconciliation,Other Reconciling Items, Percent							0.00%	0.00%	[1]	0.00%	[1]
Effective Income Tax Rate Reconciliation, Other Adjustments, Percent							0.10%	0.00%	[1]	(0.10%)	[1]
Effective Income Tax Rate Reconciliation, Percent							24.80%	35.80%	[1]	38.30%	[1]
Components of Income Tax Expense (Benefit), Continuing Operations [Abstract]
Current Federal Tax Expense (Benefit)							$ 7,600,000	$ 2,800,000		$ 5,400,000
Current State and Local Tax Expense (Benefit)							1,700,000	0		100,000
Current Change In Unrecognized Tax Expense (Benefit)							200,000	(3,700,000)		500,000
Deferred Federal Income Tax Expense (Benefit)							15,600,000	32,900,000		29,600,000
Deferred State and Local Income Tax Expense (Benefit)							7,400,000	8,000,000		8,200,000
Deferred Change In Unrecognized Tax Expense (Benefit)							300,000	4,700,000		(400,000)
Deferred investment tax credits							(500,000)	(500,000)		(500,000)
Income Tax Expense (Benefit)							32,300,000	44,200,000		42,900,000
Deferred Income Tax Expense (Benefit), Continuing Operations [Abstract]
Deferred tax expense (benefit) excluding selected items							24,000,000	(173,900,000)		39,500,000
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities							(700,000)	219,500,000		(2,100,000)
Deferred Income Tax Expense (Benefit)							$ 23,300,000	45,600,000		$ 37,400,000
Deferred Tax Liabilities, Gross [Abstract]
Deferred Tax Liabilities, Property, Plant and Equipment													281,100,000	269,500,000
Deferred Tax Liabilities, Regulatory Assets													55,400,000	58,400,000
Deferred Tax Liabilities, Compensation and Benefits, Employee Benefits													13,900,000	14,200,000
Deferred Tax Liabilities, Other													6,900,000	7,000,000
Deferred Tax Liabilities, Gross													357,300,000	349,100,000
Deferred Tax Assets, Gross [Abstract]
Deferred Tax Assets Regulatory Liabilities													53,400,000	55,800,000
Deferred Tax Assets, Operating Loss Carryforwards													400,000	12,600,000
Deferred Tax Assets Environmental Remediation													7,800,000	8,100,000
Deferred Tax Assets Tax credit carryforward													4,700,000	4,600,000
Deferred Tax Assets, Tax Deferred Expense, Compensation and Benefits, Employee Benefits													4,100,000	3,900,000
Deferred Tax Assets Deferred Investment Tax Credits													3,000,000	3,200,000
Deferred Tax Assets, Other													3,200,000	4,200,000
Deferred Tax Assets, Net of Valuation Allowance													76,600,000	92,400,000
Deferred Tax Liabilities, Net													280,700,000	256,700,000
Internal Revenue Service (IRS)
Tax Audits [Abstract]
Operating Loss Carryforwards													0	57,800,000
Tax Credit Carryforward, Amount													4,700,000	4,300,000
Carryforward expiration date range, low							2,021
Carryforward expiration date range, high							2,038
Tax years under examination, Concluded					2012 and 2013
Year(s) under examination			2014 - 2016			2012 and 2013						2010 and 2011
Year of carryback claim under examination												2,009
Potential Tax Adjustments			$ 0
WISCONSIN
Tax Audits [Abstract]
Tax years under examination, Concluded				2012 - 2013
Earliest Open Tax Year Subject To Examination							2,014
Year(s) under examination			2014 - 2016
Potential Tax Adjustments			$ 0	$ 0
State and Local Jurisdiction
Tax Audits [Abstract]
Operating Loss Carryforwards													$ 2,500,000	$ 5,400,000
Carryforward expiration date range, low							2,031
Carryforward expiration date range, high							2,033
Plant Related Regulatory Liability [Member]
Federal Tax Reform [Abstract]
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]
Federal Tax Reform [Abstract]
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]
Federal Tax Reform [Abstract]
Tax Cuts and Jobs Act of 2017, Incomplete Accounting, Change in Tax Rate, Regulatory Asset, Provisional Income Tax Expense (Benefit)								$ 23,000,000
[1]	Prior periods have been reclassified to conform to current year presentation.
[2]	ARAM is a method to flow back excess deferred taxes to customers.
[3]	ARAM has been deferred when regulatory treatment has not been established. As Xcel Energy received direction from its regulatory commissions regarding the return of excess deferred taxes to customers, the ARAM deferral was reversed. This resulted in a reduction to tax expense with a corresponding reduction to revenue.

Fair Value of Financial Asset_3

Fair Value of Financial Assets and Liabilities, Derivative Instruments (Details) MMBTU in Millions, $ in Millions		Dec. 31, 2018USD ($)MMBTU	Dec. 31, 2017MMBTU
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
Natural Gas Commodity (in million British thermal units)
Gross Notional Amounts of Commodity Options [Abstract]
Derivative, Nonmonetary Notional amount | MMBTU	[1],[2]	1.2	0
[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 Asset_4

Fair Value of Financial Assets and Liabilities, Financial Impact of Qualifying Cash Flow Hedges (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
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	$ (0.1)	$ (0.1)	$ (0.2)
After-tax net realized losses on derivative transactions reclassified into earnings	0.1	0	0.1
Accumulated other comprehensive loss related to cash flow hedges at Dec. 31	$ 0	$ (0.1)	$ (0.1)

Fair Value of Financial Asset_5

Fair Value of Financial Assets and Liabilities, Impact of Derivative Activity (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Financial Impact of Qualifying Fair Value Hedges on Earnings [Abstract]
Derivative instruments designated as fair value hedges	$ 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	(0.1)	(0.1)	(0.1)
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	(0.1)	(0.3)	(0.2)
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities)	$ (0.3)	$ 0.2	$ 0.8

Fair Value of Financial Asset_6

Fair Value of Financial Assets and Liabilities, Derivative Assets and Liabilities at Fair Value (Details) - USD ($) $ in Millions		Dec. 31, 2018	Dec. 31, 2017
Derivatives, Fair Value [Line Items]
Prepayments		$ 3.3	$ 3.5
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]	0.2
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset	[2]	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
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		0.2
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
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis
Derivatives, Fair Value [Line Items]
Prepayments		3.3
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		$ 0.2
[1]	Notional amounts for options are included on a gross basis, but are weighted for the probability of exercise.
[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, 2018. The counterparty netting excludes settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.

Fair Value of Financial Asset_7

Fair Value of Financial Assets and Liabilities, Fair Value of Long-Term Debt (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Carrying Amount
Financial Liabilities, Balance Sheet Groupings [Abstract]
Long-term debt, including current portion	$ 807.5	$ 761.2
Fair Value
Financial Liabilities, Balance Sheet Groupings [Abstract]
Long-term debt, including current portion	$ 850.4	$ 856.1

Benefit Plans and Other Postr_3

Benefit Plans and Other Postretirement Benefits, Pension Benefits (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Pension Benefits [Abstract]
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	$ 1
Pension Plan [Member]
Pension Benefits [Abstract]
Total benefit obligation		139.8	156.8	$ 157.5
Net benefit cost recognized for financial reporting		$ 10.7	$ 10.5	$ 7.6
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%	7.10%
Target Pension Asset Allocations [Abstract]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage		100.00%	100.00%
Pension Plan [Member] | Domestic and international equity securities
Target Pension Asset Allocations [Abstract]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage		37.00%	38.00%
Pension Plan [Member] | Long-duration fixed income and interest rate swap securities
Target Pension Asset Allocations [Abstract]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage		28.00%	23.00%
Pension Plan [Member] | Short-to-intermediate fixed income securities
Target Pension Asset Allocations [Abstract]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage		18.00%	21.00%
Pension Plan [Member] | Alternative investments
Target Pension Asset Allocations [Abstract]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage		15.00%	16.00%
Pension Plan [Member] | Cash
Target Pension Asset Allocations [Abstract]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage		2.00%	2.00%
Scenario, Forecast [Member] | Pension Plan [Member]
Pension Benefits [Abstract]
Expected average long-term rate of return on assets for next fiscal year (as a percent)	7.10%
Parent Company [Member] | Supplemental Executive Retirement Plan (SERP) and Nonqualified Pension Plan
Pension Benefits [Abstract]
Total benefit obligation		$ 33	$ 37
Net benefit cost recognized for financial reporting		$ 4	$ 5

Benefit Plans and Other Postr_4

Benefit Plans and Other Postretirement Benefits, Fair Value of Pension Plan Assets (Details) - Pension Plan [Member] - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	$ 109.5	$ 124.9	$ 119
Plan assets at net asset value	40.5	45.8
Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	46.6	54.9
Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	22.4	24.2
Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Debt Securities [Member]
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	22.2	24.1
Plan assets at net asset value	0	0
Debt Securities [Member] | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Debt Securities [Member] | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	22.2	24.1
Debt Securities [Member] | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Domestic and international equity securities
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	4.6	4.9
Plan assets at net asset value	0	0
Domestic and international equity securities | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	4.6	4.9
Domestic and international equity securities | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Domestic and international equity 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
Cash equivalents
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	4.9	8.1
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	4.9	8.1
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
Other
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	(1.1)	(1.2)
Plan assets at net asset value	(1.3)	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	(1.3)
Other | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0.2	0.1
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
Commingled funds
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	78.9	89.1
Plan assets at net asset value	41.8	45.9
Commingled funds | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	37.1	43.2
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
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

Benefit Plans and Other Postr_5

Benefit Plans and Other Postretirement Benefits, Pension Plan Benefit Obligations, Cash Flows and Benefit Costs (Details) $ in Millions	1 Months Ended	12 Months Ended
	Jan. 31, 2019USD ($)	Dec. 31, 2019USD ($)Plan	Dec. 31, 2018USD ($)Plan	Dec. 31, 2017USD ($)Plan	Dec. 31, 2016USD ($)Plan
Components of Net Periodic Benefit Cost (Credit) [Abstract]
Settlement Charge Recognized in Operating and Maintenance Expenses			$ 201.9	$ 201.2	$ 192
Significant Assumptions Used to Measure Costs [Abstract]
Expected average long-term rate of return on assets for next fiscal year (as a percent)			7.10%
Liability, Defined Benefit Plan, Noncurrent			$ (44.5)	(50)
Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Benefit Obligation, Contributions by Plan Participant			0	0
Accumulated Benefit Obligation at Dec. 31			129.4	145.4
Change in Projected Benefit Obligation [Roll Forward]
Obligation at Jan. 1	$ 139.8	$ 139.8	156.8	157.5
Service cost			4.8	4.6	4.4
Interest cost			5.4	6.2	6.9
Plan amendments			0	(0.7)
Actuarial loss			(13.4)	6.5
Benefit payments			(13.8)	(17.3)
Obligation at Dec. 31			139.8	156.8	157.5
Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1	109.5	$ 109.5	124.9	119
Actual return (loss) on plan assets			(11.1)	13.9
Defined Benefit Plan, Plan Assets, Contributions by Plan Participant			0	0
Employer contributions			9.5	9.3
Benefit payments			(13.8)	(17.3)
Fair value of plan assets at Dec. 31			109.5	124.9	119
Defined Benefit Plan, Plan Assets, Payment for Settlement			10.4
Funded Status of Plans at Dec. 31 [Abstract]
Funded status			(30.3)	(31.9)
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost [Abstract]
Net loss			74.3	80.4
Prior service (credit) cost			(0.3)	(0.3)
Total			74	80.1
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			5.3	5.5
Noncurrent regulatory assets			68.7	74.6
Deferred income taxes			0	0
Net-of-tax accumulated other comprehensive income			0	0
Total			$ 74	$ 80.1
Significant Assumptions Used to Measure Benefit Obligations [Abstract]
Discount rate for year-end valuation (as a percent)			4.31%	3.63%
Expected average long-term increase in compensation level (as a percent)			3.75%	3.75%
Mortality table			RP2014	RP2014
Cash Flows [Abstract]
Payment for Pension Benefits			$ 10	$ 9	7
Components of Net Periodic Benefit Cost (Credit) [Abstract]
Service cost			4.8	4.6	4.4
Interest cost			5.4	6.2	6.9
Expected return on plan assets			(9)	(9.2)	(9.2)
Amortization of prior service cost (credit)			0	0.1	0.1
Amortization of net loss			5.7	5.9	5.4
Settlement charge			7.2	7.1	0
Net periodic benefit cost			14.1	14.7	7.6
Net benefit cost recognized for financial reporting			10.7	10.5	$ 7.6
Settlement Charge Recognized in Operating and Maintenance Expenses			$ 2	$ 2
Significant Assumptions Used to Measure Costs [Abstract]
Discount rate (as a percent)			3.63%	4.13%	4.66%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase			3.75%	3.75%	4.00%
Liability, Defined Benefit Plan, Current			$ 0	$ 0
Liability, Defined Benefit Plan, Noncurrent			(30.3)	(31.9)
Defined Benefit Plan, Amounts for Asset (Liability) Recognized in Statement of Financial Position			(30.3)	(31.9)
Defined Benefit Plan Credits (Costs) Not Recognized Due To Effects of Regulation			$ (3.4)	$ (4.2)	$ 0
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Rate of Return on Plan Assets			7.10%	7.10%	7.10%
Amounts Not Yet Recognized As Components Of Net Periodic Benefit Cost Recorded As Current Regulatory Liabilities			$ 0	$ 0
Amounts Not Yet Recognized As Components Of Net Periodic Benefit Cost Recorded As Noncurrent Regulatory Liabilities			0	$ 0
Subsequent Event | Pension Plan [Member]
Cash Flows [Abstract]
Payment for Pension Benefits	$ 7
Parent Company [Member] | Pension Plan [Member]
Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Plan Assets, Payment for Settlement			$ 198
Cash Flows [Abstract]
Number of pension plans to which contributions were made | Plan			4	4	4
Payment for Pension Benefits			$ 150	$ 162	$ 125
Parent Company [Member] | Subsequent Event | Pension Plan [Member]
Cash Flows [Abstract]
Number of pension plans to which contributions were made | Plan		4
Payment for Pension Benefits		$ 150

Benefit Plans and Other Postr_6

Benefit Plans and Other Postretirement Benefits, Defined Contribution Plans (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Defined Contribution Plans [Abstract]
Contributions to 401(k) and other defined contribution plans	$ 2	$ 1	$ 1

Benefit Plans and Other Postr_7

Benefit Plans and Other Postretirement Benefits, Postretirement Health Care Benefits (Details) - Other Postretirement Benefits Plan [Member]	Dec. 31, 2018	Dec. 31, 2017
Postretirement Health Care Benefits [Abstract]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	100.00%	100.00%
Domestic and international equity securities
Postretirement Health Care Benefits [Abstract]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	18.00%	24.00%
Short-to-intermediate fixed income securities
Postretirement Health Care Benefits [Abstract]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	70.00%	60.00%
Alternative investments
Postretirement Health Care Benefits [Abstract]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	8.00%	9.00%
Cash
Postretirement Health Care Benefits [Abstract]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	4.00%	7.00%

Benefit Plans and Other Postr_8

Benefit Plans and Other Postretirement Benefits, Fair Value of Postretirement Benefit Plan Assets (Details) - Other Postretirement Benefits Plan [Member] - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	100.00%	100.00%
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	$ 0.4	$ 1.1	$ 0.5
Plan assets at net asset value	0	0
Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0.1	0.5
Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0.3	0.6
Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Debt Securities [Member]
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0.2	0.5
Plan assets at net asset value	0	0
Debt Securities [Member] | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Debt Securities [Member] | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0.2	0.5
Debt Securities [Member] | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	$ 0	$ 0
Cash equivalents
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	4.00%	7.00%
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	$ 0	$ 0.1
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	0	0.1
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	0.1	0.1
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	0.1	0.1
Insurance contracts | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Commingled funds
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0.1	0.3
Plan assets at net asset value	0	0
Commingled funds | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0.1	0.3
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
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
Domestic and international equity securities
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	18.00%	24.00%
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	$ 0	$ 0.1
Plan assets at net asset value	0	0
Domestic and international equity securities | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0.1
Domestic and international equity securities | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets	0	0
Domestic and international equity 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
Long-duration fixed income and interest rate swap securities
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	0.00%	0.00%
Short-to-intermediate fixed income securities
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	70.00%	60.00%
Alternative investments
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	8.00%	9.00%

Benefit Plans and Other Postr_9

Benefit Plans and Other Postretirement Benefits, Postretirement Benefit Plan Benefit Obligations, Cash Flows and Benefit Costs (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Funded Status of Plans at Dec. 31 [Abstract]
Noncurrent liabilities		$ (44.5)	$ (50)
Cash Flows [Abstract]
Total contributions to Xcel Energy's postretirement health care plans during the year		0.3	2	$ 1
Other Postretirement Benefits Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Benefit Obligation, Contributions by Plan Participant			0.1
Plan amendments		0	0
Change in Projected Benefit Obligation [Roll Forward]
Obligation at Jan. 1	$ 12.8	16.4	15
Service cost		0	0	0
Interest cost		0.6	0.6	0.7
Actuarial loss		(3.3)	2.1
Benefit payments		(0.9)	(1.4)
Obligation at Dec. 31		12.8	16.4	15
Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1	0.4	1.1	0.5
Actual return (loss) on plan assets		0	0
Defined Benefit Plan, Plan Assets, Contributions by Plan Participant		0	0.1
Employer contributions		0.2	1.9
Benefit payments		(0.9)	(1.4)
Fair value of plan assets at Dec. 31		0.4	1.1	0.5
Funded Status of Plans at Dec. 31 [Abstract]
Funded status		(12.4)	(15.3)
Current liabilities		(0.8)	(0.3)
Noncurrent liabilities		(11.6)	(15)
Net postretirement amounts recognized on consolidated balance sheets		(12.4)	(15.3)
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost [Abstract]
Net loss		6.8	10.6
Prior service (credit) cost		(1.4)	(1.8)
Total		5.4	8.8
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost Have Been Recorded as Follows Based Upon Expected Recovery in Rates [Abstract]
Current regulatory assets		0.2	0.1
Noncurrent regulatory assets		5.2	8.7
Current regulatory liabilities		0	0
Noncurrent regulatory liabilities		0	0
Deferred income taxes		0	0
Net-of-tax accumulated other comprehensive income		0	0
Total		$ 5.4	$ 8.8
Significant Assumptions Used to Measure Benefit Obligations [Abstract]
Discount rate for year-end valuation (as a percent)		4.32%	3.62%
Mortality table		RP2014	RP2014
Defined Benefit Plan, Health Care Cost Trend Rate Assumed, Pre-65		6.50%	7.00%
Defined Benefit Plan, Health Care Cost Trend Rate Assumed, Post-65		5.30%	5.50%
Ultimate health care trend assumption rate (as a percent)		4.50%	4.50%
Period until ultimate trend rate is reached (in years)		4	5
Components of Net Periodic Benefit Cost (Credit) [Abstract]
Service cost		$ 0	$ 0	0
Interest cost		0.6	0.6	0.7
Expected return on plan assets		(0.1)	0	0
Amortization of prior service cost (credit)		(0.4)	(0.4)	(0.4)
Amortization of net loss		0.6	0.4	0.3
Settlement charge		0	0	0
Net periodic benefit cost		$ 0.7	$ 0.6	$ 0.6
Significant Assumptions Used to Measure Costs [Abstract]
Discount rate (as a percent)		3.62%	4.13%	4.65%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase		0.00%	0.00%	0.00%
Expected average long-term rate of return on assets (as a percent)		5.30%	5.80%	5.80%
Defined Benefit Plan Credits (Costs) Not Recognized Due To Effects of Regulation		$ 0	$ 0	$ 0
Net benefit cost recognized for financial reporting		0.7	0.6	0.6
Parent Company [Member]
Cash Flows [Abstract]
Total contributions to Xcel Energy's postretirement health care plans during the year		$ 11	$ 20	$ 18
Subsequent Event
Cash Flows [Abstract]
Expected contribution to postretirement health care plans during 2018	1
Subsequent Event | Parent Company [Member]
Cash Flows [Abstract]
Expected contribution to postretirement health care plans during 2018	$ 11

Benefit Plans and Other Post_10

Benefit Plans and Other Postretirement Benefits, Projected Benefit Payments (Details) $ in Millions	Dec. 31, 2018USD ($)
Pension Plan [Member]
Defined Benefit Plan, Gross Projected Benefit Payments [Abstract]
2,019	$ 14.6
2,020	10.9
2,021	10.9
2,022	10.8
2,023	11.1
2024-2028	55.5
Other Postretirement Benefits Plan [Member]
Defined Benefit Plan, Gross Projected Benefit Payments [Abstract]
2,019	1.2
2,020	1.1
2,021	1.1
2,022	1
2,023	1
2024-2028	4.2
Expected Medicare Part D Subsidies [Abstract]
2,019	0
2,020	0
2,021	0
2,022	0
2,023	0
2024-2028	0
Defined Benefit Plan, Net Projected Benefit Payments [Abstract]
2,019	1.2
2,020	1.1
2,021	1.1
2,022	1
2,023	1
2024-2028	$ 4.2

Commitments and Contingencies,

Commitments and Contingencies, Fuel Contracts (Details) $ in Millions	12 Months Ended
	Dec. 31, 2018USD ($)
Fuel Contracts [Abstract]
Minimum annual tolerance band percentage for future rate recovery or refund of fuel costs	2.00%
Coal
Fuel Contracts [Abstract]
2,019	$ 6.1
2,020	2.3
2,021	0.6
2,022	0.7
2,023	0.7
Thereafter	0
Total	10.4
Natural Gas Supply
Fuel Contracts [Abstract]
2,019	9.9
2,020	0.3
2,021	0.4
2,022	0.2
2,023	0
Thereafter	0
Total	10.8
Natural Gas Storage and Transportation
Fuel Contracts [Abstract]
2,019	13.4
2,020	11.8
2,021	11.3
2,022	9.7
2,023	7.9
Thereafter	24.3
Total	$ 78.4
Minimum
Unrecorded Unconditional Purchase Obligation [Line Items]
Fuel Contract Expiration Date	2,019
Maximum
Unrecorded Unconditional Purchase Obligation [Line Items]
Fuel Contract Expiration Date	2,029

Commitments and Contingencies_2

Commitments and Contingencies, Leases (Details) - Office Space and Other Equipment - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Operating Leases [Abstract]
Total expenses under operating lease obligations	$ 1.3	$ 1.2	$ 1.2
Operating Leases, Future Minimum Payments Due [Abstract]
2,019	1
2,020	0.9
2,021	0.8
2,022	0.8
2,023	0.8
Thereafter	3.8
Total	$ 8.1

Commitments and Contingencies_3

Commitments and Contingencies, Variable Interest Entities (Details) - Low-Income Housing Limited Partnerships - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Amount Reflected in Consolidated Balance Sheets [Abstract]
Current assets	$ 0.3	$ 0.4
Property, plant and equipment, net	0.9	1.9
Other noncurrent assets	0.1	0.1
Total assets	1.3	2.4
Current liabilities	0	1.2
Mortgages and other long-term debt payable	0.5	0.5
Other noncurrent liabilities	0	0.1
Total liabilities	$ 0.5	$ 1.8

Commitments and Contingencies_4

Commitments and Contingencies, Joint Operating System (Details) $ in Millions	12 Months Ended
	Dec. 31, 2018USD ($)PlantCounterpartyReactor
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	13,600
Maximum assessments per reactor per accident	$ 137.6
Number of owned and licensed reactors | Reactor	3
Maximum funding requirement per reactor for any one year	$ 20.5
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	$ 18
Maximum assessment for property damage insurance NSP-Minnesota is subject to each calendar year	39
NSP-Minnesota | Maximum | Nuclear Insurance
Joint Operating System [Abstract]
Maximum possible loss contingency	$ 14,100

Commitments and Contingencies_5

Commitments and Contingencies, Guarantees (Details) - Payment or Performance Guarantee - Customer Loans for Farm Rewiring Program	12 Months Ended
	Dec. 31, 2018USD ($)
Guarantee [Abstract]
Assets held as collateral	$ 0
Guarantees issued and outstanding	1,000,000
Current exposure under these guarantees	$ 0
Guarantee Expiration Date (year)	2,020
Guarantee Obligations Claims made	$ 0

Commitments and Contingencies_6

Commitments and Contingencies, Environmental Contingencies - Site Contingencies (Details) $ in Millions	12 Months Ended
	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)
Federal Clean Water Act Section 316(b)
Manufactured Gas Plant (MGP) Site [Abstract]
Minimum Number of Plants Which Could Be Required to Make Improvements to Reduce Entrainment	2
Capital Addition Purchase Commitments [Member] | Federal Clean Water Act Section 316(b)
Manufactured Gas Plant (MGP) Site [Abstract]
Liability for Estimated Cost to Comply with Entrainment Regulation	$ 4
Ashland MGP Site
Manufactured Gas Plant (MGP) Site [Abstract]
Current Cost Estimate for Site Remediation	192
Estimated Amount Spent on Cleanup	165
Accrual for Environmental Loss Contingencies, Gross	$ 27	$ 30
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, Landfill, or Disposal Sites [Domain]
Manufactured Gas Plant (MGP) Site [Abstract]
Number of Identified MGP sites Under Current Investigation and/or Remediation	2
Liability for Estimated Cost of Remediating Site	$ 1.7	$ 0.1

Commitments and Contingencies_7

Commitments and Contingencies, Asset Retirement Obligations (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Asset Retirement Obligations [Line Items]
Asset Retirement Obligation, Liabilities Settled	$ 0	$ 0
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	14.4	11.4
Asset Retirement Obligation, Liabilities Incurred	0	1
Accretion	0.5	0.3
Cash Flow Revisions	3	1.7
Ending balance	17.9	14.4
Electric Plant Steam Production Asbestos
Asset Retirement Obligations [Line Items]
Asset Retirement Obligation, Liabilities Settled	0	0
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	3.7	2.7
Asset Retirement Obligation, Liabilities Incurred	0	1
Accretion	0.1	0
Cash Flow Revisions	0	0
Ending balance	3.8	3.7
Electric Plant Electric Distribution
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	0
Accretion	0
Cash Flow Revisions	4.6
Ending balance	4.6	0
Electric Plant Other
Asset Retirement Obligations [Line Items]
Asset Retirement Obligation, Liabilities Settled	0	0
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	0.4	0.4
Asset Retirement Obligation, Liabilities Incurred	0	0
Accretion	0	0
Cash Flow Revisions	0	0
Ending balance	0.4	0.4
Natural Gas Plant Gas Distribution
Asset Retirement Obligations [Line Items]
Asset Retirement Obligation, Liabilities Settled	0	0
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	10.3	8.3
Asset Retirement Obligation, Liabilities Incurred	0	0
Accretion	0.4	0.3
Cash Flow Revisions	(1.6)	1.7
Ending balance	9.1	10.3
Removal Costs
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Regulatory Liabilities	$ 158	$ 146

Commitments and Contingencies C

Commitments and Contingencies Commitments and Contingencies, Removal Costs (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Removal Costs
Regulatory Liabilities [Line Items]
Regulatory Liabilities	$ 158	$ 146

Commitments and Contingencies_8

Commitments and Contingencies, Legal Contingencies (Details)	1 Months Ended					12 Months Ended
	Nov. 30, 2017	Sep. 30, 2016	Dec. 31, 2015	Feb. 28, 2015	Nov. 30, 2013	Dec. 31, 2018	Dec. 31, 2017
Gas Trading Litigation
Loss Contingencies [Line Items]
Loss Contingency, Pending Claims, Number						2
Loss Contingency, Settled Claims, number						4
Summary Judgment Granted Against Plaintiff [Member] | Gas Trading Litigation
Loss Contingencies [Line Items]
Loss Contingency, Number of Plaintiffs	2
Remaining in the Litigation [Member] | Gas Trading Litigation
Loss Contingencies [Line Items]
Loss Contingency, Number of Plaintiffs	3
FERC Proceeding, MISO ROE Complaint [Member] | NSP-Minnesota
Loss Contingencies [Line Items]
Public Utilities, Base Return On Equity Charged To Customers Through Transmission Formula Rates				12.38%	12.38%
Public Utilities, ROE developed with new approach						10.28%
Public Utilities, ROE Applicable To Transmission Formula Rates In The MISO Region, Recommended By Third Parties				8.67%	9.15%
Public Utilities, Number of steps required						2
Federal Energy Regulatory Commission (FERC) [Member] | FERC Proceeding, MISO ROE Complaint [Member] | NSP-Minnesota
Loss Contingencies [Line Items]
Public Utilities, ROE Applicable To Transmission Formula Rates In The MISO Region, Approved		10.32%	10.32%
Public Utilities, ROE Applicable To Transmission Formula Rates In The MISO Region, with RTO Adder, Approved							10.82%

Other Comprehensive Income (Det

Other Comprehensive Income (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Accumulated Other Comprehensive Income (Loss) [Line Items]
Income tax expense (benefit)	$ 32.3	$ 44.2	$ 42.9
Accumulated other comprehensive loss at beginning of period	876.6
Accumulated other comprehensive loss at end of period	942.4	876.6
Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Accumulated other comprehensive loss at beginning of period	(0.1)	(0.1)
Accumulated other comprehensive loss at end of period	0	(0.1)	$ (0.1)
AOCI Attributable to Parent, Net of Tax [Roll Forward]
(Gains) losses reclassified from net accumulated other comprehensive loss	0.1	0
Net current period other comprehensive income (loss)	0.1	0
Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent [Member] | Amounts Reclassified from Accumulated Other Comprehensive Loss
Accumulated Other Comprehensive Income (Loss) [Line Items]
Income tax expense (benefit)	$ 0	$ 0

Segments and Related Informat_3

Segments and Related Information (Details) - USD ($) $ in Millions		3 Months Ended								12 Months Ended
		Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax										$ 1,021.5	$ 1,005.5	$ 957.2
Depreciation and amortization										126.1	111.2	98.3
Total interest charges and financing costs										35.2	32.2	32.6
Income tax expense (benefit)										32.3	44.2	42.9
Net income (loss)		$ 20.4	$ 31	$ 15.2	$ 31.4	$ 20.4	$ 22.3	$ 14.3	$ 22.4	98	79.4	69.1
Regulated Electric
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax										879	882.4	850.3
Intercompany Revenue										157.9	177.2	170.5
Depreciation and amortization										97.8	88.9	81.3
Total interest charges and financing costs										31.8	29.4	29.7
Income tax expense (benefit)										28.4	38.9	40.5
Net income (loss)										85.5	70.9	65
Regulated Natural Gas
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax										142	122.7	106.7
Depreciation and amortization										28.1	22.1	16.8
Total interest charges and financing costs										3.3	2.8	2.9
Income tax expense (benefit)										4.5	4	2.4
Net income (loss)										12.5	7.8	4.5
All Other
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	[1]									1.3	1.2	1.1
Depreciation and amortization										0.2	0.2	0.2
Total interest charges and financing costs										0.1	0	0
Income tax expense (benefit)										(0.6)	1.3	0
Net income (loss)										0	0.7	(0.4)
Operating Segments
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax										1,022.3	1,006.3	958.1
Operating Segments | Regulated Electric
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	[1]									878.6	881.9	849.9
Operating Segments | Regulated Natural Gas
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	[1]									141.6	122.4	106.2
Intersegment Eliminations
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax										(0.8)	(0.8)	(0.9)
Intersegment Eliminations | Regulated Electric
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax										0.4	0.5	0.4
Intersegment Eliminations | Regulated Natural Gas
Segment Reporting Information [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax										$ 0.4	$ 0.3	$ 0.5
[1]	(a) Operating revenues include $157.9 million, $177.2 million and $170.5 million of intercompany revenue for the years ended Dec. 31, 2018, 2017 and 2016, respectively. See Note 13 for further information.

Related Party Transactions (Det

Related Party Transactions (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Operating revenues
Related Party Transaction, Electric Domestic Regulated Revenue	$ 157.9	$ 177.2	$ 170.4
Operating expenses
Purchased power	410.9	421.6	413.6
Transmission expense	62.8	68.6	61.9
Other operating expenses - paid to Xcel Energy Services Inc.	86.9	92.7	$ 106.5
Accounts Receivable and Payable with Affiliates [Abstract]
Accounts receivable	15.1	3.4
Accounts payable	20	29.6
NSP-Minnesota
Accounts Receivable and Payable with Affiliates [Abstract]
Accounts receivable	0	0
Accounts payable	11	17.8
PSCo
Accounts Receivable and Payable with Affiliates [Abstract]
Accounts receivable	0.2	0
Accounts payable	0	0
Other subsidiaries of Xcel Energy Inc.
Accounts Receivable and Payable with Affiliates [Abstract]
Accounts receivable	14.9	3.4
Accounts payable	$ 9	$ 11.8

Summarized Quarterly Financia_3

Summarized Quarterly Financial Data (Unaudited) (Details) - USD ($) $ in Millions	3 Months Ended																12 Months Ended
	Dec. 31, 2018		Sep. 30, 2018		Jun. 30, 2018		Mar. 31, 2018		Dec. 31, 2017		Sep. 30, 2017		Jun. 30, 2017		Mar. 31, 2017		Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Quarterly Financial Information Disclosure [Abstract]
Operating revenues	$ 260.6		$ 256		$ 231.8		$ 273.1		$ 263		$ 247.5		$ 230.1		$ 264.9		$ 1,021.5	$ 1,005.5	$ 957.2
Operating income	34.9	[1]	48	[1]	27.5	[1]	49	[1]	40.2	[1]	39.2	[1]	29.7	[1]	43.5	[1]	159.4	152.6	142.8
Net income	$ 20.4		$ 31		$ 15.2		$ 31.4		$ 20.4		$ 22.3		$ 14.3		$ 22.4		$ 98	$ 79.4	$ 69.1
[1]	(a) In 2018, NSP-Wisconsin implemented ASU No. 2017-07 related to net periodic benefit cost, which resulted in retrospective reclassification of pension costs from O&M expense to other income.

Schedule II, Valuation and Qu_2

Schedule II, Valuation and Qualifying Accounts (Details) - Allowance for Bad Debts - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
SEC Schedule, 12-09, Movement in Valuation Allowances and Reserves [Roll Forward]
Balance at Jan. 1	$ 4.9	$ 4.9	$ 5.1
Charged to costs and expenses	4.2	4.1	3.7
Charged to other accounts	1	0.9	1.1
Deductions from reserves	(4.5)	(5)	(5)
Balance at Dec. 31	$ 5.6	$ 4.9	$ 4.9