NORTHERN STATES POWER CO /WI/, 10-K filed on 2/24/2017
Annual Report
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Document and Entity Information - USD ($)
 12 Months Ended
Dec. 31, 2016
Feb. 24, 2017
Jun. 30, 2016
Document and Entity Information [Abstract]      
Entity Registrant Name NORTHERN STATES POWER CO /WI/    
Entity Central Index Key 0000072909    
Current Fiscal Year End Date --12-31    
Entity Filer Category Non-accelerated Filer    
Document Type 10-K    
Document Period End Date Dec. 31, 2016    
Document Fiscal Year Focus 2016    
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
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CONSOLIDATED STATEMENTS OF INCOME - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Operating revenues      
Electric $ 849,946 $ 834,998 $ 829,748
Natural gas 106,157 120,147 169,629
Other 1,130 1,396 1,085
Total operating revenues 957,233 956,541 1,000,462
Operating expenses      
Electric fuel and purchased power, non-affiliates 15,574 10,795 19,595
Purchased power, affiliates 413,615 419,028 425,471
Cost of natural gas sold and transported 54,436 70,988 114,250
Operating and maintenance expenses 194,927 179,413 191,213
Conservation program expenses 12,645 11,695 11,537
Depreciation and amortization 98,294 91,245 79,654
Taxes (other than income taxes) 27,814 28,181 27,114
Loss on Monticello life cycle management/extended power uprate project 0 5,237 0
Total operating expenses 817,305 816,582 868,834
Operating income 139,928 139,959 131,628
Other income, net 461 883 270
Allowance for funds used during construction — equity 4,277 7,253 7,060
Interest charges and financing costs      
Interest charges — includes other financing costs of $1,854, $1,738, and $1,570, respectively 34,452 32,731 29,273
Public Utilities, Allowance For Funds Used During Construction, Capitalized Cost Of Debt (1,823) (3,510) (3,360)
Total interest charges and financing costs 32,629 29,221 25,913
Income before income taxes 112,037 118,874 113,045
Income taxes 42,902 44,238 42,403
Net income $ 69,135 $ 74,636 $ 70,642
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CONSOLIDATED STATEMENTS OF INCOME (Parenthetical) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Interest charges and financing costs      
Other financing costs $ 1,854 $ 1,738 $ 1,570
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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Comprehensive income:      
Net income $ 69,135 $ 74,636 $ 70,642
Derivative instruments:      
Reclassification of losses to net income, net of tax of $51 for the years ended Dec. 31, 2016, 2015, and 2014, respectively. 76 76 76
Other comprehensive income 76 76 76
Comprehensive income $ 69,211 $ 74,712 $ 70,718
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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($)
 12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Derivative instruments:      
Reclassification of losses to net income, net of tax $ (51) $ (51) $ (51)
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CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Operating activities      
Net income $ 69,135 $ 74,636 $ 70,642
Adjustments to reconcile net income to cash provided by operating activities:      
Depreciation and amortization 99,824 92,656 80,875
Deferred income taxes 37,368 45,833 45,396
Amortization of investment tax credits (523) (528) (527)
Allowance for equity funds used during construction (4,277) (7,253) (7,060)
Loss on Monticello life cycle management/extended power uprate project 0 5,237 0
Provision for bad debts 3,730 3,947 4,431
Net derivative losses 160 482 10
Other (623) 0 0
Changes in operating assets and liabilities:      
Accounts receivable (1,383) 71 (5,558)
Accrued unbilled revenues (5,940) 5,869 (1,933)
Inventories 3,250 3,126 (3,210)
Other current assets (1,191) 7,135 (3,501)
Accounts payable 10,632 (7,626) 2,936
Net regulatory assets and liabilities (18,601) (27,114) (34,697)
Other current liabilities 14,036 5,147 (911)
Pension and other employee benefit obligations (6,197) (3,177) (6,134)
Change in other noncurrent assets (718) 209 (113)
Change in other noncurrent liabilities 2,050 716 2,534
Net cash provided by operating activities 200,732 199,366 143,180
Investing activities      
Utility capital/construction expenditures (204,427) (251,797) (288,209)
Allowance for equity funds used during construction 4,277 7,253 7,060
Other, net 1,198 (224) (166)
Net cash used in investing activities (198,952) (244,768) (281,315)
Financing activities      
Proceeds from (repayments of) short-term borrowings, net 50,000 (68,000) 10,000
Proceeds from notes payable to affiliates 0 0 30
Proceeds from issuance of long-term debt 0 97,969 98,534
Repayments of long-term debt (93) (87) (107)
Capital contributions from parent 1,935 69,243 73,432
Dividends paid to parent (53,100) (53,929) (43,818)
Other, net (55) 0 0
Net cash (used in) provided by financing activities (1,313) 45,196 138,071
Net change in cash and cash equivalents 467 (206) (64)
Cash and cash equivalents at beginning of period 1,079 1,285 1,349
Cash and cash equivalents at end of period 1,546 1,079 1,285
Supplemental disclosure of cash flow information:      
Cash paid for interest (net of amounts capitalized) (30,878) (27,491) (24,442)
Cash received for income taxes, net 5,873 5,762 3,474
Supplemental disclosure of non-cash investing transactions:      
Property, plant and equipment additions in accounts payable $ 16,172 $ 16,729 $ 35,267
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CONSOLIDATED BALANCE SHEETS - USD ($)
$ in Thousands
Dec. 31, 2016
Dec. 31, 2015
Current assets    
Cash and cash equivalents $ 1,546 $ 1,079
Accounts receivable, net [1] 54,031 56,378
Accrued unbilled revenues 53,638 47,698
Inventories 18,309 21,559
Regulatory assets 18,162 16,146
Prepaid taxes 25,915 25,976
Prepayments and other 3,785 2,387
Total current assets 175,386 171,223
Property, plant and equipment, net 1,947,637 1,828,079
Other assets    
Regulatory assets 286,188 289,196
Other investments 2,844 4,042
Other 785 67
Total other assets 289,817 293,305
Total assets 2,412,840 2,292,607
Current liabilities    
Current portion of long-term debt 1,123 1,131
Short-term debt 60,000 10,000
Notes payable to affiliates 500 500
Accounts payable 41,068 34,317
Accounts payable to affiliates 29,037 24,538
Dividends payable to parent 10,729 15,322
Regulatory liabilities 17,428 11,781
Environmental liabilities 41,438 17,155
Accrued interest 8,012 7,945
Other 26,484 15,146
Total current liabilities 235,819 137,835
Deferred credits and other liabilities    
Deferred Tax Liabilities, Net, Noncurrent 430,593 391,063
Deferred investment tax credits 8,037 8,560
Regulatory liabilities 148,189 141,289
Environmental liabilities 23,003 77,441
Customer advances 19,425 18,480
Pension and employee benefit obligations 55,164 49,889
Other 18,814 16,347
Total deferred credits and other liabilities 703,225 703,069
Commitments and contingencies
Capitalization    
Long-term debt 661,946 661,318
Common stock — 1,000,000 shares authorized of $100 par value; 933,000 shares outstanding at Dec. 31, 2016 and 2015, respectively 93,300 93,300
Additional paid in capital 395,315 394,553
Retained earnings 323,368 302,741
Accumulated other comprehensive loss (133) (209)
Total common stockholder’s equity 811,850 790,385
Total liabilities and equity $ 2,412,840 $ 2,292,607
[1] Accounts receivable, net includes an immaterial amount due from affiliates for 2016 and 2015, respectively.
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CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares
Dec. 31, 2016
Dec. 31, 2015
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
v3.6.0.2
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY - USD ($)
$ in Thousands
Total
Common stock
Additional Paid In Capital
Retained Earnings
Accumulated Other Comprehensive Loss
Beginning Balance at Dec. 31, 2013 $ 604,282 $ 93,300 $ 248,844 $ 262,499 $ (361)
Balance (in shares) at Dec. 31, 2013   933,000      
Comprehensive income:          
Net income 70,642     70,642  
Other comprehensive income 76       76
Common dividends declared to parent (50,743)     (50,743)  
Contribution of capital by parent 73,432   73,432    
Ending Balance at Dec. 31, 2014 697,689 $ 93,300 322,276 282,398 (285)
Balance (in shares) at Dec. 31, 2014   933,000      
Comprehensive income:          
Net income 74,636     74,636  
Other comprehensive income 76       76
Common dividends declared to parent (54,293)     (54,293)  
Contribution of capital by parent 72,277   72,277    
Ending Balance at Dec. 31, 2015 $ 790,385 $ 93,300 394,553 302,741 (209)
Balance (in shares) at Dec. 31, 2015 933,000 933,000      
Comprehensive income:          
Net income $ 69,135     69,135  
Other comprehensive income 76       76
Common dividends declared to parent (48,508)     (48,508)  
Contribution of capital by parent 762   762    
Ending Balance at Dec. 31, 2016 $ 811,850 $ 93,300 $ 395,315 $ 323,368 $ (133)
Balance (in shares) at Dec. 31, 2016 933,000 933,000      
v3.6.0.2
CONSOLIDATED STATEMENTS OF CAPITALIZATION - USD ($)
$ in Thousands
Dec. 31, 2016
Dec. 31, 2015
Schedule of Capitalization, Long-term Debt [Line Items]    
Unamortized discount $ (2,865) $ (3,131)
Unamortized Debt Issuance Expense (4,697) (5,144)
Total long-term debt, including current maturities 663,069 662,449
Less: current maturities 1,123 1,131
Total long-term debt 661,946 661,318
Common Stockholders' Equity    
Common stock — 1,000,000 shares authorized of $100 par value; 933,000 shares outstanding at Dec. 31, 2016 and 2015, respectively 93,300 93,300
Additional paid in capital 395,315 394,553
Retained earnings 323,368 302,741
Accumulated other comprehensive loss (133) (209)
Total common stockholder’s equity 811,850 790,385
First Mortgage Bonds | Series Due Oct. 1, 2018    
Schedule of Capitalization, Long-term Debt [Line Items]    
Long-term debt, gross 150,000 150,000
First Mortgage Bonds | Series Due June 15, 2024    
Schedule of Capitalization, Long-term Debt [Line Items]    
Long-term debt, gross 200,000 200,000
First Mortgage Bonds | Series Due Sept. 1, 2038    
Schedule of Capitalization, Long-term Debt [Line Items]    
Long-term debt, gross 200,000 200,000
First Mortgage Bonds | Series Due Oct. 1, 2042    
Schedule of Capitalization, Long-term Debt [Line Items]    
Long-term debt, gross 100,000 100,000
City of La Crosse Resource Recovery Bond | Series Due Nov. 1, 2021    
Schedule of Capitalization, Long-term Debt [Line Items]    
Long-term debt, gross [1] 18,600 18,600
Fort McCoy System Acquisition | Due Oct. 15, 2030    
Schedule of Capitalization, Long-term Debt [Line Items]    
Long-term debt, gross 456 490
Other    
Schedule of Capitalization, Long-term Debt [Line Items]    
Long-term debt, gross $ 1,575 $ 1,634
[1] Resource recovery financing
v3.6.0.2
CONSOLIDATED STATEMENTS OF CAPITALIZATION (Parenthetical) - $ / shares
 12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Common Stockholders Equity [Abstract]    
Common stock, shares authorized (in shares) 1,000,000 1,000,000
Common stock, par value (in dollars per share) $ 100 $ 100
Common stock, shares outstanding (in shares) 933,000 933,000
First Mortgage Bonds | Series Due Oct. 1, 2018    
Schedule of Capitalization, Long-term Debt [Line Items]    
Debt instrument, interest rate stated percentage (in hundredths) 5.25% 5.25%
Debt instrument, maturity date Oct. 01, 2018 Oct. 01, 2018
First Mortgage Bonds | Series Due June 15, 2024    
Schedule of Capitalization, Long-term Debt [Line Items]    
Debt instrument, interest rate stated percentage (in hundredths) 3.30% 3.30%
Debt instrument, maturity date Jun. 15, 2024 Jun. 15, 2024
First Mortgage Bonds | Series Due Sept. 1, 2038    
Schedule of Capitalization, Long-term Debt [Line Items]    
Debt instrument, interest rate stated percentage (in hundredths) 6.375% 6.375%
Debt instrument, maturity date Sep. 01, 2038 Sep. 01, 2038
First Mortgage Bonds | Series Due Oct. 1, 2042    
Schedule of Capitalization, Long-term Debt [Line Items]    
Debt instrument, interest rate stated percentage (in hundredths) 3.70% 3.70%
Debt instrument, maturity date Oct. 01, 2042 Oct. 01, 2042
City of La Crosse Resource Recovery Bond | Series Due Nov. 1, 2021    
Schedule of Capitalization, Long-term Debt [Line Items]    
Debt instrument, interest rate stated percentage (in hundredths) 6.00% 6.00%
Debt instrument, maturity date Nov. 01, 2021 Nov. 01, 2021
Fort McCoy System Acquisition | Due Oct. 15, 2030    
Schedule of Capitalization, Long-term Debt [Line Items]    
Debt instrument, interest rate stated percentage (in hundredths) 7.00% 7.00%
Debt instrument, maturity date Oct. 15, 2030 Oct. 15, 2030
v3.6.0.2
Summary of Significant Accounting Policies
 12 Months Ended
Dec. 31, 2016
Accounting Policies [Abstract]  
Summary of Significant Accounting Policies
Summary of Significant Accounting Policies

Business and System of Accounts — NSP-Wisconsin is engaged in the regulated generation, transmission, distribution and sale of electricity and in the regulated purchase, transportation, distribution and sale of natural gas.  NSP-Wisconsin’s consolidated financial statements and disclosures are presented in accordance with GAAP.  All of NSP-Wisconsin’s underlying accounting records also conform to the FERC uniform system of accounts or to systems required by various state regulatory commissions, which are the same in all material respects.

Principles of Consolidation — NSP-Wisconsin’s consolidated financial statements include its wholly-owned subsidiaries and variable interest entities for which it is the primary beneficiary.  In the consolidation process, all intercompany transactions and balances are eliminated. NSP-Wisconsin has investments in certain transmission facilities jointly owned with nonaffiliated utilities. NSP-Wisconsin’s proportionate share of jointly owned facilities is recorded as property, plant and equipment on the consolidated balance sheets and NSP-Wisconsin’s proportionate share of the operating costs associated with these facilities is included in its consolidated statements of income. See Note 5 for further discussion of jointly owned transmission facilities and related ownership percentages.

NSP-Wisconsin evaluates its arrangements and contracts with other entities to determine if the other party is a variable interest entity, if NSP-Wisconsin has a variable interest and if NSP-Wisconsin is the primary beneficiary.  NSP-Wisconsin follows accounting guidance for variable interest entities which requires consideration of the activities that most significantly impact an entity’s financial performance and power to direct those activities, when determining whether NSP-Wisconsin is a variable interest entity’s primary beneficiary. See Note 11 for further discussion of variable interest entities.

Use of Estimates — In recording transactions and balances resulting from business operations, NSP-Wisconsin uses estimates based on the best information available. Estimates are used for such items as plant depreciable lives or potential disallowances, AROs, certain regulatory assets and liabilities, tax provisions, uncollectible amounts, environmental costs, unbilled revenues, jurisdictional fuel and energy cost allocations and actuarially determined benefit costs. The recorded estimates are revised when better information becomes available or when actual amounts can be determined. Those revisions can affect operating results.

Regulatory Accounting — NSP-Wisconsin accounts for certain income and expense items in accordance with accounting guidance for regulated operations. Under this guidance:

•
Certain costs, which would otherwise be charged to expense or OCI, are deferred as regulatory assets based on the expected ability to recover the costs in future rates; and
•
Certain credits, which would otherwise be reflected as income or OCI, are deferred as regulatory liabilities based on the expectation the amounts will be returned to customers in future rates, or because the amounts were collected in rates prior to the costs being incurred.

Estimates of recovering deferred costs and returning deferred credits are based on specific ratemaking decisions or precedent for each item. Regulatory assets and liabilities are amortized consistent with the treatment in the rate setting process.

If restructuring or other changes in the regulatory environment occur, NSP-Wisconsin may no longer be eligible to apply this accounting treatment, and may be required to eliminate regulatory assets and liabilities from its balance sheets.  Such changes could have a material effect on NSP-Wisconsin’s financial condition, results of operations and cash flows.  See Note 12 for further discussion of regulatory assets and liabilities.

Revenue Recognition — Revenues related to the sale of energy are generally recorded when service is rendered or energy is delivered to customers. However, the determination of the energy sales to individual customers is based on the reading of their meter, which occurs on a systematic basis throughout the month.  At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated and the corresponding unbilled revenue is recognized.  NSP-Wisconsin presents its revenues net of any excise or other fiduciary-type taxes or fees.

NSP-Wisconsin has various rate-adjustment mechanisms in place that provide for the recovery of purchased natural gas, electric fuel and purchased energy costs.  These cost-adjustment tariffs may increase or decrease the level of revenue collected from customers and are revised periodically, for differences between the total amount collected under the clauses and the costs incurred.  When applicable, under governing regulatory commission rate orders, fuel cost over-recoveries (the excess of fuel revenue billed to customers over fuel costs incurred) are deferred as regulatory liabilities and under-recoveries (the excess of fuel costs incurred over fuel revenues billed to customers) are deferred as regulatory assets. Under Wisconsin rules, NSP-Wisconsin must submit a forward looking fuel cost plan annually for approval by the PSCW. The rules also allow for deferral of any under-collection or over-collection of fuel costs in excess of a two percent annual tolerance band, for future rate recovery or refund, subject to PSCW approval.

Conservation Programs — NSP-Wisconsin participates in and funds conservation programs in its retail jurisdictions to assist customers in conserving energy and reducing peak demand on the electric and natural gas systems.  NSP-Wisconsin recovers approved conservation program costs in base rate revenue.

For operations in the state of Wisconsin, NSP-Wisconsin is required to contribute 1.2 percent of its three-year average annual operating revenues to the statewide energy efficiency and renewable resource program Focus on Energy. Funding is collected through base rates, and there is no financial incentive provided to the utility. The PSCW has full oversight of Focus on Energy including auditing and verification of programs. The program portfolio is outsourced to a third-party administrator who subcontracts as necessary to implement programs.

Property, Plant and Equipment and Depreciation — Property, plant and equipment is stated at original cost. The cost of plant includes direct labor and materials, contracted work, overhead costs and AFUDC. The cost of plant retired is charged to accumulated depreciation and amortization. Amounts recovered in rates for future removal costs are recorded as regulatory liabilities. Significant additions or improvements extending asset lives are capitalized, while repairs and maintenance costs are charged to expense as incurred. Maintenance and replacement of items determined to be less than a unit of property are charged to operating expenses as incurred. Planned major maintenance activities are charged to operating expense unless the cost represents the acquisition of an additional unit of property or the replacement of an existing unit of property.  Property, plant and equipment also includes costs associated with property held for future use.  The depreciable lives of certain plant assets are reviewed annually and revised, if appropriate.

Property, plant and equipment is tested for impairment when it is determined that the carrying value of the assets may not be recoverable. A loss is recognized in the current period if it becomes probable that part of a cost of a plant under construction or recently completed plant will be disallowed for recovery from customers and a reasonable estimate of the disallowance can be made. For investments in property, plant and equipment that are abandoned and not expected to go into service, incurred costs and related deferred tax amounts are compared to the discounted estimated future rate recovery, and a loss is recognized, if necessary.

NSP-Wisconsin records depreciation expense related to its plant using the straight-line method over the plant’s useful life. Actuarial life studies are performed and submitted to the state and federal commissions for review.  Upon acceptance by the various commissions, the resulting lives and net salvage rates are used to calculate depreciation.  Depreciation expense, expressed as a percentage of average depreciable property, was approximately 3.3, 3.4 and 3.3 percent for the years ended Dec. 31, 2016, 2015 and 2014, respectively.

Leases — NSP-Wisconsin evaluates a variety of contracts for lease classification at inception, including rental arrangements for office space, vehicles and equipment.  Contracts determined to contain a lease because of per unit pricing that is other than fixed or market price, terms regarding the use of a particular asset, and other factors are evaluated further to determine if the arrangement is a capital lease. See Note 11 for further discussion of leases.

AFUDC — AFUDC represents the cost of capital used to finance utility construction activity. AFUDC is computed by applying a composite financing rate to qualified CWIP. The amount of AFUDC capitalized as a utility construction cost is credited to nonoperating income (for equity capital) and interest charges (for debt capital). AFUDC amounts capitalized are included in NSP-Wisconsin’s rate base for establishing utility service rates.

Generally, AFUDC costs are recovered from customers as the related property is depreciated.  However, in some cases, the PSCW has allowed an AFUDC calculation greater than the FERC-defined AFUDC rate, resulting in higher recognition of AFUDC. In some cases for certain transmission projects, the FERC has approved a more current recovery of the cost of capital associated with large capital projects, resulting in a lower recognition of AFUDC.

AROs — NSP-Wisconsin accounts for AROs under accounting guidance that requires a liability for the fair value of an ARO to be recognized in the period in which it is incurred if it can be reasonably estimated, with the offsetting associated asset retirement costs capitalized as a long-lived asset. The liability is generally increased over time by applying the effective interest method of accretion, and the capitalized costs are depreciated over the useful life of the long-lived asset. Changes resulting from revisions to the timing or amount of expected asset retirement cash flows are recognized as an increase or a decrease in the ARO. NSP-Wisconsin also recovers through rates certain future plant removal costs in addition to AROs. The accumulated removal costs for these obligations are reflected in the balance sheets as a regulatory liability. See Note 11 for further discussion of AROs.

Income Taxes — NSP-Wisconsin accounts for income taxes using the asset and liability method, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the financial statements. NSP-Wisconsin defers income taxes for all temporary differences between pretax financial and taxable income, and between the book and tax bases of assets and liabilities.  NSP-Wisconsin uses the tax rates that are scheduled to be in effect when the temporary differences are expected to reverse. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period that includes the enactment date.

Deferred tax assets are reduced by a valuation allowance if it is more likely than not that some portion or all of the deferred tax asset will not be realized. In making such a determination, all available evidence is considered, including scheduled reversals of deferred tax liabilities, projected future taxable income, tax planning strategies and recent financial operations.

Due to the effects of past regulatory practices, when deferred taxes were not required to be recorded due to the use of flow through accounting for ratemaking purposes, the reversal of some temporary differences are accounted for as current income tax expense. Tax credits are recorded when earned unless there is a requirement to defer the benefit and amortize it over the book depreciable lives of the related property. The requirement to defer and amortize tax credits only applies to federal ITCs related to public utility property. Utility rate regulation also has resulted in the recognition of certain regulatory assets and liabilities related to income taxes, which are summarized in Note 12.

NSP-Wisconsin follows the applicable accounting guidance to measure and disclose uncertain tax positions that it has taken or expects to take in its income tax returns.  NSP-Wisconsin recognizes a tax position in its consolidated financial statements when it is more likely than not that the position will be sustained upon examination based on the technical merits of the position.  Recognition of changes in uncertain tax positions are reflected as a component of income tax.

NSP-Wisconsin reports interest and penalties related to income taxes within the other income and interest charges sections in the consolidated statements of income.

Xcel Energy Inc. and its subsidiaries, including NSP-Wisconsin, file consolidated federal income tax returns as well as combined or separate state income tax returns.  Federal income taxes paid by Xcel Energy Inc. are allocated to Xcel Energy Inc.’s subsidiaries based on separate company computations of tax.  A similar allocation is made for state income taxes paid by Xcel Energy Inc. in connection with combined state filings. Xcel Energy Inc. also allocates its own income tax benefits to its direct subsidiaries which are recorded directly in equity by the subsidiaries based on the relative positive tax liabilities of the subsidiaries.

See Note 6 for further discussion of income taxes.

Types of and Accounting for Derivative Instruments — NSP-Wisconsin uses derivative instruments in connection with its utility commodity price and interest rate activities, including forward contracts, futures, swaps and options.  All derivative instruments not designated and qualifying for the normal purchases and normal sales exception, as defined by the accounting guidance for derivatives and hedging, are recorded on the consolidated balance sheets at fair value as derivative instruments.  This includes certain instruments used to mitigate market risk for the utility operations.  The classification of changes in fair value for those derivative instruments is dependent on the designation of a qualifying hedging relationship.  Changes in fair value of derivative instruments not designated in a qualifying hedging relationship are reflected in current earnings or as a regulatory asset or liability.  The classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms.

Interest rate hedging transactions are recorded as a component of interest expense.  NSP-Wisconsin is allowed to recover in electric or natural gas rates the costs of certain financial instruments purchased to reduce commodity cost volatility.  For further information on derivatives entered to mitigate commodity price risk on behalf of electric and natural gas customers, see Note 9.

Cash Flow Hedges — Certain qualifying hedging relationships are designated as a hedge of a forecasted transaction or future cash flow (cash flow hedge). Changes in the fair value of a derivative designated as a cash flow hedge, to the extent effective, are included in OCI, or deferred as a regulatory asset or liability based on recovery mechanisms until earnings are affected by the hedged transaction.

Normal Purchases and Normal Sales — NSP-Wisconsin enters into contracts for the purchase and sale of commodities for use in its business operations. Derivatives and hedging accounting guidance requires a company to evaluate these contracts to determine whether the contracts are derivatives.  Certain contracts that meet the definition of a derivative may be exempted from derivative accounting if designated as normal purchases or normal sales.

NSP-Wisconsin evaluates all of its contracts at inception to determine if they are derivatives and if they meet the normal purchases and normal sales designation requirements.  See Note 9 for further discussion of NSP-Wisconsin’s risk management and derivative activities.

Fair Value Measurements — NSP-Wisconsin presents cash equivalents, interest rate derivatives and commodity derivatives at estimated fair values in its consolidated financial statements.  Cash equivalents are recorded at cost plus accrued interest; money market funds are measured using quoted NAVs.  For interest rate derivatives, quoted prices based primarily on observable market interest rate curves are used as a primary input to establish fair value.  For commodity derivatives, the most observable inputs available are generally used to determine the fair value of each contract.  In the absence of a quoted price for an identical contract in an active market, NSP-Wisconsin may use quoted prices for similar contracts, or internally prepared valuation models to determine fair value. See Note 9 for further discussion.

Cash and Cash Equivalents — NSP-Wisconsin considers investments in certain instruments, including commercial paper and money market funds, with a remaining maturity of three months or less at the time of purchase, to be cash equivalents.

Accounts Receivable and Allowance for Bad Debts — Accounts receivable are stated at the actual billed amount net of an allowance for bad debts. NSP-Wisconsin establishes an allowance for uncollectible receivables based on a policy that reflects its expected exposure to the credit risk of customers.

Inventory — All inventory is recorded at average cost.

RECs — RECs are marketable environmental instruments that represent proof that energy was generated from eligible renewable energy sources. RECs are awarded upon delivery of the associated energy and can be bought and sold. RECs are typically used as a form of measurement of compliance to RPS enacted by those states that are encouraging construction and consumption from renewable energy sources, but can also be sold separately from the energy produced. NSP-Wisconsin acquires RECs from the generation or purchase of renewable power.  

When RECs are purchased or acquired in the course of generation they are recorded as inventory at cost. The cost of RECs that are utilized for compliance purposes is recorded as electric fuel and purchased power expense.

Sales of RECs that are purchased or acquired in the course of generation are recorded in electric utility operating revenues on a gross basis. The cost of these RECs and related transaction costs are recorded in electric fuel and purchased power expense.

Emission Allowances — Emission allowances, including the annual SO2 and NOx emission allowance entitlement received from the EPA, are recorded at cost plus associated broker commission fees. NSP-Wisconsin follows the inventory accounting model for all emission allowances. Sales of emission allowances are included in electric utility operating revenues and the operating activities section of the consolidated statements of cash flows.

Environmental Costs — Environmental costs are recorded when it is probable NSP-Wisconsin is liable for remediation costs and the liability can be reasonably estimated. Costs are deferred as a regulatory asset if it is probable that the costs will be recovered from customers in future rates. Otherwise, the costs are expensed. If an environmental expense is related to facilities currently in use, such as emission-control equipment, the cost is capitalized and depreciated over the life of the plant.

Estimated remediation costs, excluding inflationary increases, are recorded based on experience, an assessment of the current situation and the technology currently available for use in the remediation.  The recorded costs are regularly adjusted as estimates are revised and remediation proceeds.  If other participating PRPs exist and acknowledge their potential involvement with a site, costs are estimated and recorded only for NSP-Wisconsin’s expected share of the cost.  Any future costs of restoring sites where operation may be extended are treated as a capitalized cost of plant retirement.  The depreciation expense levels recoverable in rates include a provision for removal expenses, which may include final remediation costs.  Removal costs recovered in rates before the related costs are incurred are classified as a regulatory liability.

See Note 11 for further discussion of environmental costs.

Benefit Plans and Other Postretirement Benefits — NSP-Wisconsin maintains pension and postretirement benefit plans for eligible employees.  Recognizing the cost of providing benefits and measuring the projected benefit obligation of these plans under applicable accounting guidance requires management to make various assumptions and estimates.

Based on regulatory recovery mechanisms, certain unrecognized actuarial gains and losses and unrecognized prior service costs or credits are recorded as regulatory assets and liabilities, rather than OCI.

See Note 7 for further discussion of benefit plans and other postretirement benefits.

Guarantees — NSP-Wisconsin recognizes, upon issuance or modification of a guarantee, a liability for the fair market value of the obligation that has been assumed in issuing the guarantee.  This liability includes consideration of specific triggering events and other conditions which may modify the ongoing obligation to perform under the guarantee.

The obligation recognized is reduced over the term of the guarantee as NSP-Wisconsin is released from risk under the guarantee.  See Note 11 for specific details of issued guarantees.

Reclassifications — Due to adoption of new accounting pronouncements, certain previously reported amounts have been reclassified to conform to the current year presentation. See Note 2 for further discussion of recently adopted accounting pronouncements.

Subsequent Events — Management has evaluated the impact of events occurring after Dec. 31, 2016 up to the date of issuance of these consolidated financial statements.  These statements contain all necessary adjustments and disclosures resulting from that evaluation.
v3.6.0.2
Accounting Pronouncements
 12 Months Ended
Dec. 31, 2016
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]  
Accounting Pronouncements
Accounting Pronouncements

Recently Issued

Revenue Recognition — In May 2014, the FASB issued Revenue from Contracts with Customers, Topic 606 (ASU No. 2014-09), which provides a new framework for the recognition of revenue. NSP-Wisconsin expects its adoption will result in increased disclosures regarding revenue, cash flows and obligations related to arrangements with customers. NSP-Wisconsin has not yet fully determined the impacts of adoption for several aspects of the standard, including a determination of whether receipts of non-refundable contributions in aid of construction should be recognized as revenues or may continue to be recorded as reductions to property, plant and equipment. Also, it is yet to be determined whether and how much an evaluation of the collectability of regulated electric and gas revenues will impact the amounts of revenue recognized upon delivery. NSP-Wisconsin currently expects to implement the standard on a modified retrospective basis, which requires application to contracts with customers effective Jan. 1, 2018, with the cumulative impact on contracts not yet completed as of Dec. 31, 2017 recognized as an adjustment to the opening balance of retained earnings.

Classification and Measurement of Financial Instruments — In January 2016, the FASB issued Recognition and Measurement of Financial Assets and Financial Liabilities, Subtopic 825-10 (ASU No. 2016-01), which among other changes in accounting and disclosure requirements, replaces the cost method of accounting for non-marketable equity securities with a model for recognizing impairments and observable price changes, and also eliminates the available-for-sale classification for marketable equity securities. Under the new guidance, other than when the consolidation or equity method of accounting is utilized, changes in the fair value of equity securities are to be recognized in earnings. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, 2017. NSP-Wisconsin is currently evaluating the impact of adopting ASU No. 2016-01 on its consolidated financial statements.

Leases — In February 2016, the FASB issued Leases, Topic 842 (ASU No. 2016-02), which, for lessees, requires balance sheet recognition of right-of-use assets and lease liabilities for all leases. Additionally, for leases that qualify as finance leases, the guidance requires expense recognition consisting of amortization of the right-of-use asset as well as interest on the related lease liability using the effective interest method. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, 2018, and early adoption is permitted. NSP-Wisconsin is currently evaluating the impact of adopting ASU No. 2016-02 on its consolidated financial statements.

Recently Adopted

Consolidation — In February 2015, the FASB issued Amendments to the Consolidation Analysis, Topic 810 (ASU No. 2015-02), which reduces the number of consolidation models and amends certain consolidation principles related to variable interest entities. NSP-Wisconsin implemented the guidance on Jan. 1, 2016, and the implementation did not have a significant impact on its consolidated financial statements.

Presentation of Debt Issuance Costs — In April 2015, the FASB issued Simplifying the Presentation of Debt Issuance Costs, Subtopic 835-30 (ASU No. 2015-03), which requires the presentation of debt issuance costs on the balance sheet as a deduction from the carrying amount of the related debt, instead of presentation as an asset. NSP-Wisconsin implemented the new guidance as required on Jan. 1, 2016, and as a result, $5.1 million of such deferred costs were retrospectively reclassified from other non-current assets to long-term debt on the consolidated balance sheet as of Dec. 31, 2015.

Fair Value Measurement — In May 2015, the FASB issued Disclosures for Investments in Certain Entities that Calculate Net Asset Value per Share (or Its Equivalent), Topic 820 (ASU No. 2015-07), which eliminates the requirement to categorize fair value measurements using a NAV methodology in the fair value hierarchy. NSP-Wisconsin implemented the guidance on Jan. 1, 2016, and the implementation did not have a material impact on its consolidated financial statements. For related disclosures, see Note 7 to the consolidated financial statements.

Presentation of Deferred Taxes — In November 2015, the FASB issued Balance Sheet Classification of Deferred Taxes, Topic 740 (ASU No. 2015-17), which eliminates the requirement to present deferred tax assets and liabilities as current and noncurrent on the consolidated balance sheet based on the classification of the related asset or liability, and instead requires classification of all deferred tax assets and liabilities as noncurrent. NSP-Wisconsin early adopted the new guidance in the fourth quarter of 2016 and as a result $2.5 million of current deferred income taxes were retrospectively reclassified to offset long-term deferred income tax liabilities on the consolidated balance sheet as of Dec. 31, 2015.

Stock Compensation — In March 2016, the FASB issued Improvements to Employee Share-Based Payment Accounting, Topic 718 (ASU No. 2016-09), which simplifies accounting and financial statement presentation for share-based payment transactions. The guidance requires that the difference between the tax deduction available upon settlement of share-based equity awards and the tax benefit accumulated over the vesting period be recognized as an adjustment to income tax expense. NSP-Wisconsin adopted the guidance in 2016, and the implementation did not have a material impact on its consolidated financial statements.
v3.6.0.2
Selected Balance Sheet Data
 12 Months Ended
Dec. 31, 2016
Balance Sheet Related Disclosures [Abstract]  
Selected Balance Sheet Data
Selected Balance Sheet Data
(Thousands of Dollars)
 
Dec. 31, 2016
 
Dec. 31, 2015
Accounts receivable, net (a)
 
 
 
 
Accounts receivable
 
$
58,896

 
$
61,506

Less allowance for bad debts
 
(4,865
)
 
(5,128
)
 
 
$
54,031

 
$
56,378



(a) 
Accounts receivable, net includes an immaterial amount due from affiliates for 2016 and 2015, respectively.
(Thousands of Dollars)
 
Dec. 31, 2016
 
Dec. 31, 2015
Inventories
 
 
 
 
Materials and supplies
 
$
6,582

 
$
6,785

Fuel
 
4,743

 
6,528

Natural gas
 
6,984

 
8,246

 
 
$
18,309

 
$
21,559


(Thousands of Dollars)
 
Dec. 31, 2016
 
Dec. 31, 2015
Property, plant and equipment, net
 
 
 
 
Electric plant
 
$
2,499,401

 
$
2,411,562

Natural gas plant
 
294,986

 
275,376

Common and other property
 
156,316

 
132,329

CWIP
 
118,822

 
65,755

Total property, plant and equipment
 
3,069,525

 
2,885,022

Less accumulated depreciation
 
(1,121,888
)
 
(1,056,943
)
 
 
$
1,947,637

 
$
1,828,079
v3.6.0.2
Borrowings and Other Financing Instruments
 12 Months Ended
Dec. 31, 2016
Debt Disclosure [Abstract]  
Borrowings and Other Financing Instruments
Borrowings and Other Financing Instruments

Commercial Paper — NSP-Wisconsin meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under its credit facility. Commercial paper outstanding for NSP-Wisconsin was as follows:
(Amounts in Millions, Except Interest Rates)
 
Three Months Ended Dec. 31, 2016
Borrowing limit
 
$
150

Amount outstanding at period end
 
60

Average amount outstanding
 
32

Maximum amount outstanding
 
64

Weighted average interest rate, computed on a daily basis
 
0.73
%
Weighted average interest rate at period end
 
0.95


(Amounts in Millions, Except Interest Rates)
 
Twelve Months Ended Dec. 31, 2016
 
Twelve Months Ended Dec. 31, 2015
 
Twelve Months Ended Dec. 31, 2014
Borrowing limit
 
$
150

 
$
150

 
$
150

Amount outstanding at period end
 
60

 
10

 
78

Average amount outstanding
 
15

 
39

 
46

Maximum amount outstanding
 
64

 
122

 
101

Weighted average interest rate, computed on a daily basis
 
0.69
%
 
0.44
%
 
0.27
%
Weighted average interest rate at period end
 
0.95

 
0.70

 
0.55



Letters of Credit — NSP-Wisconsin may use letters of credit, generally with terms of one-year, to provide financial guarantees for certain operating obligations.  At Dec. 31, 2016 and 2015, there were no letters of credit outstanding.

Credit Facility — In order to use its commercial paper program to fulfill short-term funding needs, NSP-Wisconsin must have a revolving credit facility in place at least equal to the amount of its commercial paper borrowing limit and cannot issue commercial paper in an aggregate amount exceeding available capacity under this credit facility.  The line of credit provides short-term financing in the form of notes payable to banks, letters of credit and back-up support for commercial paper borrowings.

Amended Credit Agreement — In June 2016, NSP-Wisconsin entered into an amended five-year credit agreement with a syndicate of banks. The total borrowing limit under the amended credit agreement remained at $150 million. The amended credit agreement has substantially the same terms and conditions as the prior credit agreement with the following exceptions:
•
The maturity extended from October 2019 to June 2021.
•
The Eurodollar borrowing margin on this line of credit was reduced to a range of 75 to 150 basis points per year, from a range of 87.5 to 175 basis points per year, based upon applicable long-term credit ratings.
•
The commitment fees, calculated on the unused portion of the line of credit, was reduced to a range of 6 to 22.5 basis points per year, from a range of 7.5 to 27.5 basis points per year, also based on applicable long-term credit ratings.

NSP-Wisconsin has the right to request an extension of the termination date for an additional one-year period. The extension requests are subject to majority bank group approval.

Other features of NSP-Wisconsin’s credit facility include:

•
The credit facility has a financial covenant requiring that the debt-to-total capitalization ratio be less than or equal to 65 percent. NSP-Wisconsin was in compliance as its debt-to-total capitalization ratio was 47 percent and 46 percent at Dec. 31, 2016 and 2015, respectively. If NSP-Wisconsin does not comply with the covenant, an event of default may be declared, and if not remedied, any outstanding amounts due under the facility can be declared due by the lender.
•
The credit facility has a cross-default provision that provides NSP-Wisconsin will be in default on its borrowings under the facility if NSP-Wisconsin or any of its subsidiaries whose total assets exceed 15 percent of NSP-Wisconsin’s consolidated total assets, default on certain indebtedness in an aggregate principal amount exceeding $75 million.
•
NSP-Wisconsin was in compliance with all financial covenants on its debt agreements as of Dec. 31, 2016 and 2015.

At Dec. 31, 2016, NSP-Wisconsin had the following committed credit facility available (in millions):
Credit Facility (a)
 
Drawn (b)
 
Available
$
150

 
$
60

 
$
90


(a) 
This credit facility matures in June 2021.
(b) 
Includes outstanding commercial paper.

All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity under the credit facility.  NSP-Wisconsin had no direct advances on the credit facility outstanding at Dec. 31, 2016 and 2015.

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, 2016
 
Dec. 31, 2015
Notes payable to affiliates
 
$
0.5

 
$
0.5

Weighted average interest rate
 
0.95
%
 
0.87
%


Long-Term Borrowings and Other Financing Instruments

Generally, all real and personal property of NSP-Wisconsin is subject to the liens of its first mortgage indentures. Debt premiums, discounts and expenses are amortized over the life of the related debt. The premiums, discounts and expenses associated with refinanced debt are deferred and amortized over the life of the related new issuance, in accordance with regulatory guidelines.

In 2015, NSP-Wisconsin issued $100 million of 3.3 percent first mortgage bonds due June 15, 2024.

During the next five years, NSP-Wisconsin has long-term debt maturities of $150 million and $18.6 million due in 2018 and 2021, respectively.

Deferred Financing Costs — Deferred financing costs of approximately $4.7 million and $5.1 million, net of amortization, are presented as a deduction from the carrying amount of long-term debt at Dec. 31, 2016 and 2015, respectively.  NSP-Wisconsin is amortizing these financing costs over the remaining maturity periods of the related debt.

Dividend Restrictions — NSP-Wisconsin’s dividends are subject to the FERC’s jurisdiction, which prohibits the payment of dividends out of capital accounts; payment of dividends is allowed out of retained earnings only.

The most restrictive dividend limitation for NSP-Wisconsin is imposed by its state regulatory commission.  NSP-Wisconsin cannot pay annual dividends in excess of approximately $53.1 million if its calendar year average equity-to-total capitalization ratio is or falls below the state commission authorized level of 52.5 percent, as calculated consistent with PSCW requirements.  NSP-Wisconsin’s calendar year average equity-to-total capitalization ratio calculated on this basis was 53.6 percent at Dec. 31, 2016 and $33.6 million in retained earnings was not restricted.
v3.6.0.2
Joint Ownership of Transmission Facilities
 12 Months Ended
Dec. 31, 2016
Joint Ownership of Transmission Facilities [Abstract]  
Joint Ownership of Transmission Facilities
Joint Ownership of Transmission Facilities

Following are the investments by NSP-Wisconsin in jointly owned transmission facilities and the related ownership percentages as of Dec. 31, 2016:
(Thousands of Dollars)
 
Plant in
Service
 
Accumulated Depreciation
 
CWIP
 
Ownership %
Electric Transmission:
 
 
 
 
 
 
 
 
CapX2020 Transmission
 
$
164,040

 
$
10,874

 
$
42,546

 
81
%
La Crosse, Wis. to Madison, Wis.
 
—

 
—

 
41,131

 
37

Total NSP-Wisconsin
 
$
164,040

 
$
10,874

 
$
83,677

 
 


NSP-Wisconsin’s share of operating expenses and construction expenditures are included in the applicable utility accounts. Each of the respective owners is responsible for providing its own financing.
v3.6.0.2
Income Taxes
 12 Months Ended
Dec. 31, 2016
Income Tax Disclosure [Abstract]  
Income Taxes
Income Taxes

Consolidated Appropriations Act, 2016 — In December 2015, the Consolidated Appropriations Act, 2016 (Act) was signed into law. The Act provides for the following:

•
Immediate expensing, or “bonus depreciation,” of 50 percent for property placed in service in 2015, 2016, and 2017; 40 percent for property placed in service in 2018; and 30 percent for property placed in service in 2019. Additionally, some longer production period property placed in service in 2020 will be eligible for bonus depreciation;
•
PTCs at 100 percent of the credit rate ($0.023 per KWh) for wind energy projects that begin construction by the end of 2016; 80 percent of the credit rate for projects that begin construction in 2017; 60 percent of the credit rate for projects that begin construction in 2018; and 40 percent of the credit rate for projects that begin construction in 2019. The wind energy PTC was not extended for projects that begin construction after 2019;
•
ITCs at 30 percent for commercial solar projects that begin construction by the end of 2019; 26 percent for projects that begin construction in 2020; 22 percent for projects that begin construction in 2021; and 10 percent for projects thereafter;
•
R&E credit was permanently extended; and
•
Delay of two years (until 2020) of the excise tax on certain employer-provided health insurance plans.

The accounting related to the Act was recorded beginning in the fourth quarter of 2015 because a change in tax law is accounted for beginning in the period of enactment.

Tax Increase Prevention Act of 2014 — In 2014, the Tax Increase Prevention Act (TIPA) was signed into law. The TIPA provides for the following:

•
The R&E credit was extended for 2014;
•
PTCs were extended for projects that began construction before the end of 2014 with certain projects qualifying into future years; and
•
50 percent bonus depreciation was extended one year through 2014. Additionally, some longer production period property placed in service in 2015 is also eligible for 50 percent bonus depreciation.

The accounting related to the TIPA was recorded beginning in the fourth quarter of 2014 because a change in tax law is accounted for in the period of enactment.

Federal Audit — NSP-Wisconsin is a member of the Xcel Energy affiliated group that files a consolidated federal income tax return. In 2012, the IRS commenced an examination of tax years 2010 and 2011, including a 2009 carryback claim. As of Dec. 31, 2016, the IRS had proposed an adjustment to the federal tax loss carryback claims that would result in $14 million of income tax expense for the 2009 through 2011 claims, and the 2013 through 2015 claims. In the fourth quarter of 2015, the IRS forwarded the issue to the Office of Appeals (Appeals). In 2016, the IRS audit team and Xcel Energy presented their cases to Appeals; however, the outcome and timing of a resolution is uncertain. The statute of limitations applicable to Xcel Energy’s 2009 through 2011 federal income tax returns, following extensions, expires in December 2017. Xcel Energy has recognized its best estimate of income tax expense that will result from a final resolution of the IRS’ proposed adjustment of the carryback claims. NSP-Wisconsin is not expected to accrue any income tax expense related to this adjustment.

In the third quarter of 2015, the IRS commenced an examination of tax years 2012 and 2013. As of Dec. 31, 2016, the IRS had not proposed any material adjustments to tax years 2012 and 2013. Subsequent to year-end, the IRS proposed an adjustment to tax years 2012 through 2013 that may impact Xcel Energy’s NOL and tax credit carryforwards and ETR. However, Xcel Energy is continuing to evaluate the IRS’ proposal and the outcome and timing of a resolution is uncertain.

State Audits — NSP-Wisconsin is a member of the Xcel Energy affiliated group that files consolidated state income tax returns. As of Dec. 31, 2016, NSP-Wisconsin’s earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations is 2012. In August 2016, Wisconsin began an audit of years 2012 and 2013. As of Dec. 31, 2016, Wisconsin had not proposed any adjustments, and there were no other state income tax audits in progress.

Unrecognized Tax Benefits — The unrecognized tax benefit balance includes permanent tax positions, which if recognized would affect the annual ETR. In addition, the unrecognized tax benefit balance includes temporary tax positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. A change in the period of deductibility would not affect the ETR but would accelerate the payment of cash to the taxing authority to an earlier period.

A reconciliation of the amount of unrecognized tax benefit is as follows:
(Millions of Dollars)
 
Dec. 31, 2016
 
Dec. 31, 2015
Unrecognized tax benefit — Permanent tax positions
 
$
0.4

 
$
0.2

Unrecognized tax benefit — Temporary tax positions
 
4.9

 
4.3

Total unrecognized tax benefit
 
$
5.3

 
$
4.5


A reconciliation of the beginning and ending amount of unrecognized tax benefit is as follows:
(Millions of Dollars)
 
2016
 
2015
 
2014
Balance at Jan. 1
 
$
4.5

 
$
3.0

 
$
1.5

Additions based on tax positions related to the current year
 
0.5

 
1.9

 
1.9

Reductions based on tax positions related to the current year
 
—

 
(0.3
)
 
(0.2
)
Additions for tax positions of prior years
 
0.5

 
0.8

 
0.1

Reductions for tax positions of prior years
 
(0.2
)
 
(0.9
)
 
(0.2
)
Settlements with taxing authorities
 
—

 
—

 
(0.1
)
Balance at Dec. 31
 
$
5.3

 
$
4.5

 
$
3.0



The unrecognized tax benefit amounts were reduced by the tax benefits associated with NOL and tax credit carryforwards.  The amounts of tax benefits associated with NOL and tax credit carryforwards are as follows:
(Millions of Dollars)
 
Dec. 31, 2016
 
Dec. 31, 2015
NOL and tax credit carryforwards
 
$
(1.2
)
 
$
(0.9
)


It is reasonably possible that NSP-Wisconsin’s amount of unrecognized tax benefits could significantly change in the next 12 months as the IRS Appeals and audit progress, the Wisconsin audit progresses, and other state audits resume. As the IRS Appeals and IRS and Wisconsin audits progress, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $2 million.

The payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryforwards. The payables for interest related to unrecognized tax benefits at Dec. 31, 2016, 2015 or 2014 were not material. No amounts were accrued for penalties related to unrecognized tax benefits as of Dec. 31, 2016, 2015 or 2014.

Other Income Tax Matters — NOL amounts represent the amount of the tax loss that is carried forward and tax credits represent the deferred tax asset. NOL and tax credit carryforwards as of Dec. 31 were as follows:
(Millions of Dollars)
 
2016
 
2015
Federal NOL carryforward
 
$
97

 
$
103

Federal tax credit carryforwards
 
4

 
5

State NOL carryforward
 
3

 
3


The federal carryforward periods expire between 2021 and 2036.  The state carryforward periods expire in 2031.

Total income tax expense from operations differs from the amount computed by applying the statutory federal income tax rate to income before income tax expense. The following reconciles such differences for the years ending Dec. 31:
 
 
2016
 
2015
 
2014
Federal statutory rate
 
35.0
 %
 
35.0
 %
 
35.0
 %
Increases (decreases) in tax from:
 
 
 
 
 
 
State income taxes, net of federal income tax benefit
 
4.9

 
4.8

 
4.9

Change in unrecognized tax benefits
 
0.1

 
0.1

 
—

Tax credits recognized
 
(0.7
)
 
(0.7
)
 
(0.7
)
Regulatory differences — utility plant items
 
(0.7
)
 
(1.7
)
 
(1.6
)
Other, net
 
(0.3
)
 
(0.3
)
 
(0.1
)
Effective income tax rate
 
38.3
 %
 
37.2
 %
 
37.5
 %


The components of income tax expense for the years ending Dec. 31 were:
(Thousands of Dollars)
 
2016
 
2015
 
2014
Current federal tax expense (benefit)
 
$
5,367

 
$
(4,715
)
 
$
(3,932
)
Current state tax expense
 
131

 
2,150

 
453

Current change in unrecognized tax expense
 
559

 
1,498

 
1,013

Deferred federal tax expense
 
29,588

 
40,580

 
38,321

Deferred state tax expense
 
8,212

 
6,675

 
8,042

Deferred change in unrecognized tax benefit
 
(432
)
 
(1,422
)
 
(967
)
Deferred investment tax credits
 
(523
)
 
(528
)
 
(527
)
Total income tax expense
 
$
42,902

 
$
44,238

 
$
42,403


The components of deferred income tax expense for the years ending Dec. 31 were:
(Thousands of Dollars)
 
2016
 
2015
 
2014
Deferred tax expense excluding items below
 
$
39,530

 
$
51,084

 
$
49,793

Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities
 
(2,112
)
 
(5,200
)
 
(4,346
)
Tax expense allocated to other comprehensive income and other
 
(50
)
 
(51
)
 
(51
)
Deferred tax expense
 
$
37,368

 
$
45,833

 
$
45,396



The components of the net deferred tax liability at Dec. 31 were as follows:
(Thousands of Dollars)
 
2016
 
2015
Deferred tax liabilities:
 
 
 
 
Difference between book and tax bases of property
 
$
412,071

 
$
382,592

Regulatory assets
 
75,392

 
78,233

Employee benefits
 
15,443

 
18,028

Other
 
9,949

 
10,190

Total deferred tax liabilities
 
$
512,855

 
$
489,043

Deferred tax assets:
 
 
 
 
NOL carryforward
 
$
35,216

 
$
37,508

Environmental remediation
 
25,842

 
37,938

Regulatory liabilities
 
5,779

 
9,328

Deferred investment tax credits
 
4,996

 
5,312

Tax credit carryforward
 
3,704

 
4,760

Other
 
6,725

 
3,134

Total deferred tax assets
 
$
82,262

 
$
97,980

Net deferred tax liability
 
$
430,593

 
$
391,063
v3.6.0.2
Benefit Plans and Other Postretirement Benefits
 12 Months Ended
Dec. 31, 2016
Compensation and Retirement Disclosure [Abstract]  
Benefit Plans and Other Postretirement Benefits
Benefit Plans and Other Postretirement Benefits

Consistent with the process for rate recovery of pension and postretirement benefits for its employees, NSP-Wisconsin accounts for its participation in, and related costs of, pension and other postretirement benefit plans sponsored by Xcel Energy Inc. as multiple employer plans. NSP-Wisconsin is responsible for its share of cash contributions, plan costs and obligations and is entitled to its share of plan assets; accordingly, NSP-Wisconsin accounts for its pro rata share of these plans, including pension expense and contributions, resulting in accounting consistent with that of a single employer plan exclusively for NSP-Wisconsin employees.

Xcel Energy, which includes NSP-Wisconsin, offers various benefit plans to its employees. Approximately 71 percent of employees that receive benefits are represented by several local labor unions under several collective-bargaining agreements. At Dec. 31, 2016, NSP-Wisconsin had 399 bargaining employees covered under a collective-bargaining agreement, which expires at the end of 2019.

The plans invest in various instruments which are disclosed under the accounting guidance for fair value measurements which establishes a hierarchical framework for disclosing the observability of the inputs utilized in measuring fair value. The three levels in the hierarchy and examples of each level are as follows:

Level 1 — Quoted prices are available in active markets for identical assets as of the reporting date. The types of assets included in Level 1 are highly liquid and actively traded instruments with quoted prices.

Level 2 — Pricing inputs are other than quoted prices in active markets, but are either directly or indirectly observable as of the reporting date. The types of assets included in Level 2 are typically either comparable to actively traded securities or contracts, or priced with models using highly observable inputs.

Level 3 — Significant inputs to pricing have little or no observability as of the reporting date. The types of assets included in Level 3 are those with inputs requiring significant management judgment or estimation.

Specific valuation methods include the following:

Cash equivalents — The fair values of cash equivalents are generally based on cost plus accrued interest; money market funds are measured using quoted NAVs.

Insurance contracts — Insurance contract fair values take into consideration the value of the investments in separate accounts of the insurer, which are priced based on observable inputs.

Investments in commingled funds, equity securities and other funds — Equity securities are valued using quoted prices in active markets. The fair values for commingled funds are measured using NAVs, which take into consideration the value of underlying fund investments, as well as the other accrued assets and liabilities of a fund, in order to determine a per share market value. The investments in commingled funds may be redeemed for NAV with proper notice. Proper notice varies by fund and can range from daily with a few days’ notice to annually with 90 days’ notice. Private equity investments require approval of the fund for any unscheduled redemption, and such redemptions may be approved or denied by the fund at its sole discretion. Depending on the fund, unscheduled distributions from real estate investments may require approval of the fund or may be redeemed with proper notice, which is typically quarterly with 45-90 days’ notice; however, withdrawals from real estate investments may be delayed or discounted as a result of fund illiquidity.

Investments in debt securities — Fair values for debt securities are determined by a third party pricing service using recent trades and observable spreads from benchmark interest rates for similar securities.

Derivative Instruments — Fair values for foreign currency derivatives are determined using pricing models based on the prevailing forward exchange rate of the underlying currencies. The fair values of interest rate derivatives are based on broker quotes that utilize current market interest rate forecasts.

Pension Benefits

Xcel Energy, which includes NSP-Wisconsin, has several noncontributory, defined benefit pension plans that cover almost all employees. Generally, benefits are based on a combination of years of service, the employee’s average pay and, in some cases, social security benefits. Xcel Energy Inc.’s and NSP-Wisconsin’s policy is to fully fund into an external trust the actuarially determined pension costs recognized for ratemaking and financial reporting purposes, subject to the limitations of applicable employee benefit and tax laws.

In addition to the qualified pension plans, Xcel Energy maintains a supplemental executive retirement plan (SERP) and a nonqualified pension plan. The SERP is maintained for certain executives that were participants in the plan in 2008, when the SERP was closed to new participants. The nonqualified pension plan provides unfunded, nonqualified benefits for compensation that is in excess of the limits applicable to the qualified pension plans, with distributions attributable to NSP-Wisconsin funded by NSP-Wisconsin’s consolidated operating cash flows. The total obligations of the SERP and nonqualified plan as of Dec. 31, 2016 and 2015 were $43.5 million and $41.8 million, respectively, of which $0.8 million and $0.7 million, respectively, was attributable to NSP-Wisconsin. In 2016 and 2015, Xcel Energy recognized net benefit cost for financial reporting for the SERP and nonqualified plans of $7.9 million and $9.5 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 as determined necessary. The amount of rabbi trust funding attributable to NSP-Wisconsin is immaterial. Also in 2016, Xcel Energy amended the deferred compensation plan to provide eligible participants the ability to diversify deferred settlements of equity awards, other than time-based equity awards, into various fund options.

Xcel Energy Inc. and NSP-Wisconsin base the investment-return assumption on expected long-term performance for each of the investment types included in the pension asset portfolio and consider the historical returns achieved by the asset portfolio over the past 20-year or longer period, as well as the long-term return levels projected and recommended by investment experts. Xcel Energy Inc. and NSP-Wisconsin continually review pension assumptions. The pension cost determination assumes a forecasted mix of investment types over the long term.

•
Investment returns in 2016 were below the assumed level of 7.10 percent;
•
Investment returns in 2015 and 2014 were below the assumed level of 7.25 percent for both years; and
•
In 2017, NSP-Wisconsin’s expected investment-return assumption is 7.10 percent.

The assets are invested in a portfolio according to Xcel Energy Inc.’s and NSP-Wisconsin’s return, liquidity and diversification objectives to provide a source of funding for plan obligations and minimize the necessity of contributions to the plan, within appropriate levels of risk. The principal mechanism for achieving these objectives is the projected allocation of assets to selected asset classes, given the long-term risk, return, and liquidity characteristics of each particular asset class. There were no significant concentrations of risk in any particular industry, index, or entity. Market volatility can impact even well-diversified portfolios and significantly affect the return levels achieved by pension assets in any year.

The following table presents the target pension asset allocations for NSP-Wisconsin at Dec. 31 for the upcoming year:
 
 
2016
 
2015
Domestic and international equity securities
 
40
%
 
41
%
Long-duration fixed income and interest rate swap securities
 
23

 
23

Short-to-intermediate fixed income securities
 
16

 
14

Alternative investments
 
19

 
20

Cash
 
2

 
2

Total
 
100
%
 
100
%


The ongoing investment strategy is based on plan-specific investment recommendations that seek to minimize potential investment and interest rate risk as a plan’s funded status increases over time. The investment recommendations result in a greater percentage of long-duration fixed income securities being allocated to specific plans having relatively higher funded status ratios and a greater percentage of growth assets being allocated to plans having relatively lower funded status ratios. The aggregate projected asset allocation presented in the table above for the master pension trust results from the plan-specific strategies.

Pension Plan Assets

The following tables present, for each of the fair value hierarchy levels, NSP-Wisconsin’s pension plan assets that are measured at fair value as of Dec. 31, 2016 and 2015:
 
 
Dec. 31, 2016
(Thousands of Dollars)
 
Level 1
 
Level 2
 
Level 3
 
Investments Measured at NAV (a)
 
Total
Cash equivalents
 
$
3,939

 
$
—

 
$
—

 
$
—

 
$
3,939

Commingled funds:
 
 
 
 
 
 
 
 
 
 
U.S. equity funds
 
—

 
—

 
—

 
21,415

 
21,415

Non U.S. equity funds
 
—

 
—

 
—

 
16,348

 
16,348

U.S. corporate bond funds
 
—

 
—

 
—

 
10,581

 
10,581

Emerging market equity funds
 
—

 
—

 
—

 
8,577

 
8,577

Emerging market debt funds
 
—

 
—

 
—

 
7,306

 
7,306

Commodity funds
 
—

 
—

 
—

 
889

 
889

Private equity investments
 
—

 
—

 
—

 
4,652

 
4,652

Real estate
 
—

 
—

 
—

 
8,108

 
8,108

Other commingled funds
 
—

 
—

 
—

 
8,752

 
8,752

Debt securities:
 
 
 
 
 
 
 
 
 
 
Government securities
 
—

 
12,773

 
—

 
—

 
12,773

U.S. corporate bonds
 
—

 
9,432

 
—

 
—

 
9,432

Non U.S. corporate bonds
 
—

 
1,514

 
—

 
—

 
1,514

Mortgage-backed securities
 
—

 
254

 
—

 
—

 
254

Asset-backed securities
 
—

 
120

 
—

 
—

 
120

Equity securities:
 
 
 
 
 
 
 
 
 
 
U.S. equities
 
4,219

 
—

 
—

 
—

 
4,219

Other
 
—

 
97

 
—

 
—

 
97

Total
 
$
8,158

 
$
24,190

 
$
—

 
$
86,628

 
$
118,976


(a) 
Based on the requirements of ASU No. 2015-07, investments measured at fair value using a NAV methodology have not been classified in the fair value hierarchy. See Note 2 for further information on the adoption of ASU No. 2015-07.

 
 
Dec. 31, 2015
(Thousands of Dollars)
 
Level 1
 
Level 2
 
Level 3
 
Investments Measured at NAV (a)
 
Total
Cash equivalents
 
$
6,005

 
$
—

 
$
—

 
$
—

 
$
6,005

Derivatives
 
—

 
89

 
—

 
—

 
89

Commingled funds:
 
 
 
 
 
 
 
 
 
 
U.S. equity funds
 
—

 
—

 
—

 
17,338

 
17,338

Non U.S. equity funds
 
—

 
—

 
—

 
16,710

 
16,710

U.S. corporate bond funds
 
—

 
—

 
—

 
10,001

 
10,001

Emerging market equity funds
 
—

 
—

 
—

 
7,491

 
7,491

Emerging market debt funds
 
—

 
—

 
—

 
7,245

 
7,245

Commodity funds
 
—

 
—

 
—

 
2,461

 
2,461

Private equity investments
 
—

 
—

 
—

 
5,967

 
5,967

Real estate
 
—

 
—

 
—

 
8,663

 
8,663

Other commingled funds
 
—

 
—

 
—

 
9,321

 
9,321

Debt securities:
 
 
 
 
 
 
 
 
 
 
Government securities
 
—

 
13,048

 
—

 
—

 
13,048

U.S. corporate bonds
 
—

 
9,008

 
—

 
—

 
9,008

Non U.S. corporate bonds
 
—

 
1,446

 
—

 
—

 
1,446

Asset-backed securities
 
—

 
101

 
—

 
—

 
101

Equity securities:
 
 
 
 
 
 
 
 
 
 
U.S. equities
 
4,213

 
—

 
—

 
—

 
4,213

Other
 
—

 
207

 
—

 
—

 
207

Total
 
$
10,218

 
$
23,899

 
$
—

 
$
85,197

 
$
119,314



(a) 
Based on the requirements of ASU No. 2015-07, investments measured at fair value using a NAV methodology have not been classified in the fair value hierarchy. See Note 2 for further information on the adoption of ASU No. 2015-07.

There were no assets transferred in or out of Level 3 for the years ended Dec. 31, 2016, 2015 or 2014.

Benefit Obligations — A comparison of the actuarially computed pension benefit obligation and plan assets for NSP-Wisconsin is presented in the following table:
(Thousands of Dollars)
 
2016
 
2015
Accumulated Benefit Obligation at Dec. 31
 
$
146,448

 
$
140,917

 
 
 
 
 
Change in Projected Benefit Obligation:
 
 
 
 
Obligation at Jan. 1
 
$
152,545

 
$
165,669

Service cost
 
4,417

 
4,759

Interest cost
 
6,816

 
6,520

Plan amendments
 
305

 
—

Actuarial loss (gain)
 
7,315

 
(11,159
)
Benefit payments
 
(13,941
)
 
(13,244
)
Obligation at Dec. 31
 
$
157,457

 
$
152,545


(Thousands of Dollars)
 
2016
 
2015
Change in Fair Value of Plan Assets:
 
 
 
 
Fair value of plan assets at Jan. 1
 
$
119,314

 
$
132,713

Actual return (loss) on plan assets
 
6,163

 
(5,087
)
Employer contributions
 
7,440

 
4,932

Benefit payments
 
(13,941
)
 
(13,244
)
Fair value of plan assets at Dec. 31
 
$
118,976

 
$
119,314


(Thousands of Dollars)
 
2016
 
2015
Funded Status of Plans at Dec. 31:
 
 
 
 
Funded status (a)
 
$
(38,481
)
 
$
(33,231
)
(a) 
Amounts are recognized in noncurrent liabilities on NSP-Wisconsin’s consolidated balance sheets.
(Thousands of Dollars)
 
2016
 
2015
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:
 
 
 
 
Net loss
 
$
91,531

 
$
86,614

Prior service cost
 
750

 
556

Total
 
$
92,281

 
$
87,170


(Thousands of Dollars)
 
2016
 
2015
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
 
$
5,972

 
$
6,300

Noncurrent regulatory assets
 
86,309

 
80,870

Total
 
$
92,281

 
$
87,170


Measurement date
 
Dec. 31, 2016
 
Dec. 31, 2015
 
 
2016
 
2015
Significant Assumptions Used to Measure Benefit Obligations:
 
 
 
 
Discount rate for year-end valuation
 
4.13
%
 
4.66
%
Expected average long-term increase in compensation level
 
3.75

 
4.00

Mortality table
 
RP 2014

 
RP 2014



Mortality — In 2014, the Society of Actuaries published a new mortality table (RP-2014) and projection scale (MP-2014) that increased the overall life expectancy of males and females. On Dec. 31, 2014 NSP-Wisconsin adopted the RP-2014 table, with modifications, based on its population and specific experience and a modified MP-2014 projection scale. During 2016, a new projection table was released (MP-2016).  In 2016, NSP-Wisconsin adopted a modified version of the MP-2016 table and will continue to utilize the RP-2014 base table, modified for company experience.

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 2014 through 2017 to meet minimum funding requirements.

Total voluntary and required pension funding contributions across all four of Xcel Energy’s pension plans were as follows:

•
$150.0 million in January 2017, of which $9.0 million was attributable to NSP-Wisconsin;
•
$125.2 million in 2016, of which $7.4 million was attributable to NSP-Wisconsin;
•
$90.1 million in 2015, of which $4.9 million was attributable to NSP-Wisconsin; and
•
$130.6 million in 2014, of which $8.0 million was attributable to NSP-Wisconsin.

For future years, Xcel Energy and NSP-Wisconsin anticipate contributions will be made as necessary.

Plan Amendments — The 2016 increase in the projected benefit obligation resulted from a change in the discount rate basis for lump sum conversion to annuity participants and annuity conversion to lump sum participants in the Xcel Energy Pension Plan. In 2015, there were no plan amendments made which affected the projected benefit obligation.

Benefit Costs — The components of NSP-Wisconsin’s net periodic pension cost were:
(Thousands of Dollars)
 
2016
 
2015
 
2014
Service cost
 
$
4,417

 
$
4,759

 
$
4,527

Interest cost
 
6,816

 
6,520

 
7,257

Expected return on plan assets
 
(9,157
)
 
(9,483
)
 
(9,642
)
Amortization of prior service cost
 
111

 
111

 
111

Amortization of net loss
 
5,392

 
6,804

 
6,617

Net periodic pension cost
 
$
7,579

 
$
8,711

 
$
8,870


 
 
2016
 
2015
 
2014
Significant Assumptions Used to Measure Costs:
 
 
 
 
 
 
Discount rate
 
4.66
%
 
4.11
%
 
4.75
%
Expected average long-term increase in compensation level
 
4.00

 
3.75

 
3.75

Expected average long-term rate of return on assets
 
7.10

 
7.25

 
7.25



In addition to the benefit costs in the table above, for the pension plans sponsored by Xcel Energy Inc., costs are allocated to NSP-Wisconsin based on Xcel Energy Services Inc. employees’ labor costs. Amounts allocated to NSP-Wisconsin were $1.6 million, $1.9 million and $1.7 million in 2016, 2015 and 2014, respectively. Pension costs include an expected return impact for the current year that may differ from actual investment performance in the plan. The return assumption used for 2017 pension cost calculations is 7.10 percent. The cost calculation uses a market-related valuation of pension assets. Xcel Energy, including NSP-Wisconsin, uses a calculated value method to determine the market-related value of the plan assets. The market-related value begins with the fair market value of assets as of the beginning of the year. The market-related value is determined by adjusting the fair market value of assets to reflect the investment gains and losses (the difference between the actual investment return and the expected investment return on the market-related value) during each of the previous five years at the rate of 20 percent per year. As these differences between actual investment returns and the expected investment returns are incorporated into the market-related value, the differences are recognized over the expected average remaining years of service for active employees.

Defined Contribution Plans

Xcel Energy, which includes NSP-Wisconsin, maintains 401(k) and other defined contribution plans that cover substantially all employees. The expense to these plans for NSP-Wisconsin was approximately $1.4 million in 2016, 2015 and 2014.

Postretirement Health Care Benefits

Xcel Energy, which includes NSP-Wisconsin, has a contributory health and welfare benefit plan that provides health care and death benefits to certain Xcel Energy retirees. NSP-Wisconsin discontinued contributing toward health care benefits for nonbargaining employees retiring after 1998 and for bargaining employees who retired after 1999.

Regulatory agencies for nearly all retail utility customers have allowed rate recovery of accrued postretirement benefit costs.

Plan Assets — Certain state agencies that regulate Xcel Energy Inc.’s utility subsidiaries also have issued guidelines related to the funding of postretirement benefit costs. These assets are invested in a manner consistent with the investment strategy for the pension plan.

The following table presents the target postretirement asset allocations for Xcel Energy Inc. and NSP-Wisconsin at Dec. 31 for the upcoming year:
 
 
2016
 
2015
Domestic and international equity securities
 
25
%
 
25
%
Short-to-intermediate fixed income securities
 
57

 
57

Alternative investments
 
13

 
13

Cash
 
5

 
5

Total
 
100
%
 
100
%


Xcel Energy Inc. and NSP-Wisconsin base investment-return assumptions for the postretirement health care fund assets on expected long-term performance for each of the investment types included in the asset portfolio. Assumptions and target allocations are determined at the master trust level. The investment mix at each of Xcel Energy Inc.’s utility subsidiaries may vary from the investment mix of the total asset portfolio. The assets are invested in a portfolio according to Xcel Energy Inc.’s and NSP-Wisconsin’s return, liquidity and diversification objectives to provide a source of funding for plan obligations and minimize the necessity of contributions to the plan, within appropriate levels of risk. The principal mechanism for achieving these objectives is the projected allocation of assets to selected asset classes, given the long-term risk, return, correlation and liquidity characteristics of each particular asset class. There were no significant concentrations of risk in any particular industry, index, or entity. Market volatility is not considered to be a material factor in postretirement health care costs.

The following tables present, for each of the fair value hierarchy levels, NSP-Wisconsin’s proportionate allocation of the total postretirement benefit plan assets that are measured at fair value as of Dec. 31, 2016 and 2015:
 
 
Dec. 31, 2016
(Thousands of Dollars)
 
Level 1
 
Level 2
 
Level 3
 
Investments Measured at NAV (a)

 
Total
Cash equivalents
 
$
25

 
$
—

 
$
—

 
$
—

 
$
25

Insurance contracts
 
—

 
58

 
—

 
—

 
58

Commingled funds:
 
 
 
 
 
 
 
 
 
 
U.S. equity funds
 
—

 
—

 
—

 
67

 
67

U.S fixed income funds
 
—

 
—

 
—

 
33

 
33

Emerging market debt funds
 
—

 
—

 
—

 
38

 
38

Other commingled funds
 
—

 
—

 
—

 
67

 
67

Debt securities:
 
 
 
 
 
 
 
 
 
 
Government securities
 
—

 
46

 
—

 
—

 
46

U.S. corporate bonds
 
—

 
77

 
—

 
—

 
77

Non U.S. corporate bonds
 
—

 
21

 
—

 
—

 
21

Asset-backed securities
 
—

 
23

 
—

 
—

 
23

Mortgage-backed securities
 
—

 
36

 
—

 
—

 
36

Equity securities:
 
 
 
 
 
 
 
 
 
 
Non U.S. equities
 
50

 
—

 
—

 
—

 
50

Other
 
—

 
2

 
—

 
—

 
2

Total
 
$
75

 
$
263

 
$
—

 
$
205

 
$
543

(a) 
Based on the requirements of ASU No. 2015-07, investments measured at fair value using a NAV methodology have not been classified in the fair value hierarchy. See Note 2 for further information on the adoption of ASU No. 2015-07.

 
 
Dec. 31, 2015
(Thousands of Dollars)
 
Level 1
 
Level 2
 
Level 3
 
Investments Measured at NAV (a)

 
Total
Cash equivalents
 
$
18

 
$
—

 
$
—

 
$
—

 
$
18

Insurance contracts
 
—

 
44

 
—

 
—

 
44

Commingled funds:
 
 
 
 
 
 
 
 
 
 
U.S. equity funds
 
—

 
—

 
—

 
36

 
36

Non U.S. equity funds
 
—

 
—

 
—

 
31

 
31

U.S fixed income funds
 
—

 
—

 
—

 
23

 
23

Emerging market equity funds
 
—

 
—

 
—

 
10

 
10

Emerging market debt funds
 
—

 
—

 
—

 
33

 
33

Other commingled funds
 
—

 
—

 
—

 
58

 
58

Debt securities:
 
 
 
 
 
 
 
 
 
 
Government securities
 
—

 
37

 
—

 
—

 
37

U.S. corporate bonds
 
—

 
56

 
—

 
—

 
56

Non U.S. corporate bonds
 
—

 
12

 
—

 
—

 
12

Asset-backed securities
 
—

 
27

 
—

 
—

 
27

Mortgage-backed securities
 
—

 
33

 
—

 
—

 
33

Total
 
$
18

 
$
209

 
$
—

 
$
191

 
$
418


(a) 
Based on the requirements of ASU No. 2015-07, investments measured at fair value using a NAV methodology have not been classified in the fair value hierarchy. See Note 2 for further information on the adoption of ASU No. 2015-07.

There were no assets transferred in or out of Level 3 for the years ended Dec. 31, 2016, 2015 and 2014.

Benefit Obligations — A comparison of the actuarially computed benefit obligation and plan assets for NSP-Wisconsin is presented in the following table:
(Thousands of Dollars)
 
2016
 
2015
Change in Projected Benefit Obligation:
 
 
 
 
Obligation at Jan. 1
 
$
14,718

 
$
16,768

Service cost
 
24

 
29

Interest cost
 
651

 
653

Medicare subsidy reimbursements
 
7

 
13

Plan participants’ contributions
 
87

 
130

Actuarial loss (gain)
 
775

 
(1,645
)
Benefit payments
 
(1,289
)
 
(1,230
)
Obligation at Dec. 31
 
$
14,973

 
$
14,718


(Thousands of Dollars)
 
2016
 
2015
Change in Fair Value of Plan Assets:
 
 
 
 
Fair value of plan assets at Jan. 1
 
$
418

 
$
512

Actual loss on plan assets
 
(12
)
 
(12
)
Plan participants’ contributions
 
87

 
130

Employer contributions
 
1,339

 
1,018

Benefit payments
 
(1,289
)
 
(1,230
)
Fair value of plan assets at Dec. 31
 
$
543

 
$
418


(Thousands of Dollars)
 
2016
 
2015
Funded Status of Plans at Dec. 31:
 
 
 
 
Funded status
 
$
(14,430
)
 
$
(14,300
)
Current liabilities
 
(822
)
 
(1,017
)
Noncurrent liabilities
 
(13,608
)
 
(13,283
)
Net postretirement amounts recognized on consolidated balance sheets
 
$
(14,430
)
 
$
(14,300
)

(Thousands of Dollars)
 
2016
 
2015
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:
 
 
 
 
Net loss
 
$
8,883

 
$
8,402

Prior service credit
 
(2,134
)
 
(2,485
)
Total
 
$
6,749

 
$
5,917


(Thousands of Dollars)
 
2016
 
2015
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
 
$
—

 
$
99

Noncurrent regulatory assets
 
6,749

 
5,818

Total
 
$
6,749

 
$
5,917


Measurement date
 
Dec. 31, 2016
 
Dec. 31, 2015
 
 
2016
 
2015
Significant Assumptions Used to Measure Benefit Obligations:
 
 
 
 
Discount rate for year-end valuation
 
4.13
%
 
4.65
%
Mortality table
 
RP 2014

 
RP 2014

Health care costs trend rate — initial
 
5.50
%
 
6.00
%


Effective Jan. 1, 2017, the initial medical trend rate was decreased from 6.0 percent to 5.5 percent. The ultimate trend assumption remained at 4.5 percent. The period until the ultimate rate is reached is two years. Xcel Energy Inc. and NSP-Wisconsin base the medical trend assumption on the long-term cost inflation expected in the health care market, considering the levels projected and recommended by industry experts, as well as recent actual medical cost increases experienced by the retiree medical plan.

A one-percent change in the assumed health care cost trend rate would have the following effects on NSP-Wisconsin:
 
 
One-Percentage Point
(Thousands of Dollars)
 
Increase
 
Decrease
APBO
 
$
1,423

 
$
(1,212
)
Service and interest components
 
71

 
(60
)


Cash Flows — The postretirement health care plans have no funding requirements under income tax and other retirement-related regulations other than fulfilling benefit payment obligations, when claims are presented and approved under the plans. Additional cash funding requirements are prescribed by certain state and federal rate regulatory authorities. Xcel Energy, which includes NSP-Wisconsin, contributed $17.9 million, $18.3 million and $17.1 million during 2016, 2015 and 2014, respectively, of which $1.3 million, $1.0 million and $1.0 million were attributable to NSP-Wisconsin. Xcel Energy expects to contribute approximately $11.8 million during 2017, of which $1.4 million is attributable to NSP-Wisconsin.

Plan Amendments — In 2016 and 2015, there were no plan amendments made which affected the benefit obligation.

Benefit Costs — The components of NSP-Wisconsin’s net periodic postretirement benefit costs were:
(Thousands of Dollars)
 
2016
 
2015
 
2014
Service cost
 
$
24

 
$
29

 
$
35

Interest cost
 
651

 
653

 
791

Expected return on plan assets
 
(24
)
 
(30
)
 
(52
)
Amortization of prior service credit
 
(351
)
 
(351
)
 
(351
)
Amortization of net loss
 
330

 
456

 
666

Net periodic postretirement benefit cost
 
$
630

 
$
757

 
$
1,089


 
 
2016
 
2015
 
2014
Significant Assumptions Used to Measure Costs:
 
 
 
 
 
 
Discount rate
 
4.65
%
 
4.08
%
 
4.82
%
Expected average long-term rate of return on assets
 
5.80

 
5.80

 
7.08



In addition to the benefit costs in the table above, for the postretirement health care plans sponsored by Xcel Energy Inc., costs are allocated to NSP-Wisconsin based on Xcel Energy Services Inc. employees’ labor costs.

Projected Benefit Payments

The following table lists NSP-Wisconsin’s projected benefit payments for the pension and postretirement benefit plans:
(Thousands of Dollars)
 
Projected Pension
Benefit Payments
 
Gross Projected
Postretirement
Health Care
Benefit Payments
 
Expected Medicare
Part D Subsidies
 
Net Projected
Postretirement
Health Care
Benefit Payments
2017
 
$
12,324

 
$
1,371

 
$
6

 
$
1,365

2018
 
11,496

 
1,308

 
5

 
1,303

2019
 
12,957

 
1,271

 
4

 
1,267

2020
 
13,329

 
1,226

 
4

 
1,222

2021
 
12,964

 
1,169

 
3

 
1,166

2022-2026
 
61,280

 
5,031

 
15

 
5,016



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, including electrical workers and other construction and facilities workers who may perform services for more than one employer during a given period and do not participate in the NSP-Wisconsin sponsored pension plans. Contributing to these types of plans creates risk that differs from providing benefits under NSP-Wisconsin sponsored plans, in that if another participating employer ceases to contribute to a multiemployer plan, additional unfunded obligations may need to be funded over time by remaining participating employers.

Contributions to multiemployer plans were as follows for the years ended Dec. 31, 2016, 2015 and 2014. There were no significant changes to the nature or magnitude of the participation of NSP-Wisconsin in multiemployer plans for the years presented:
(Thousands of Dollars)
 
2016
 
2015
 
2014
Multiemployer plan contributions:
 
 
 
 
 
 
Pension
 
$
707

 
$
944

 
$
156
v3.6.0.2
Other Income, Net
 12 Months Ended
Dec. 31, 2016
Other Income and Expenses [Abstract]  
Other Income, Net
Other Income, Net

Other income, net for the years ended Dec. 31 consisted of the following:
(Thousands of Dollars)
 
2016
 
2015
 
2014
Interest income
 
$
244

 
$
332

 
$
368

Other nonoperating income
 
208

 
789

 
321

Insurance policy expense
 
22

 
(228
)
 
(409
)
Other nonoperating expense
 
(13
)
 
(10
)
 
(10
)
Other income, net
 
$
461

 
$
883

 
$
270
v3.6.0.2
Fair Value of Financial Assets and Liabilities
 12 Months Ended
Dec. 31, 2016
Fair Value Disclosures [Abstract]  
Fair Value of Financial Assets and Liabilities
Fair Value of Financial Assets and Liabilities

Fair Value Measurements

The accounting guidance for fair value measurements and disclosures provides a single definition of fair value and requires certain disclosures about assets and liabilities measured at fair value.  A hierarchical framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value is established by this guidance. The three levels in the hierarchy are as follows:

Level 1 — Quoted prices are available in active markets for identical assets or liabilities as of the reporting date.  The types of assets and liabilities included in Level 1 are highly liquid and actively traded instruments with quoted prices.

Level 2 — Pricing inputs are other than quoted prices in active markets, but are either directly or indirectly observable as of the reporting date.  The types of assets and liabilities included in Level 2 are typically either comparable to actively traded securities or contracts, or priced with models using highly observable inputs.

Level 3 — Significant inputs to pricing have little or no observability as of the reporting date.  The types of assets and liabilities included in Level 3 are those valued with models requiring significant management judgment or estimation.

Specific valuation methods include the following:

Cash equivalents — The fair values of cash equivalents are generally based on cost plus accrued interest; money market funds are measured using quoted NAVs.

Interest rate derivatives — The fair values of interest rate derivatives are based on broker quotes that utilize current market interest rate forecasts.

Commodity derivatives — The methods used to measure the fair value of commodity derivative forwards and options utilize forward prices and volatilities, as well as pricing adjustments for specific delivery locations, and are generally assigned a Level 2.  When contractual settlements extend to periods beyond those readily observable on active exchanges or quoted by brokers, the significance of the use of less observable forecasts of long-term forward prices and volatilities on a valuation is evaluated, and may result in Level 3 classification.

Derivative Instruments Fair Value Measurements

NSP-Wisconsin enters into derivative instruments, including forward contracts, futures, swaps and options, for trading purposes and to manage risk in connection with changes in interest rates and utility commodity prices.

Interest Rate Derivatives — NSP-Wisconsin enters into various instruments that effectively fix the interest payments on certain floating rate debt obligations or effectively fix the yield or price on a specified benchmark interest rate for an anticipated debt issuance for a specific period.  These derivative instruments are generally designated as cash flow hedges for accounting purposes.

At Dec. 31, 2016, accumulated other comprehensive losses related to interest rate derivatives included $0.1 million of net losses expected to be reclassified into earnings during the next 12 months as the related hedged interest rate transactions impact earnings, including forecasted amounts for unsettled hedges, as applicable.

Commodity Derivatives — NSP-Wisconsin may enter into derivative instruments to manage variability of future cash flows from changes in commodity prices in its electric and natural gas operations, as well as for trading purposes. This could include the purchase or sale of natural gas to generate electric energy and natural gas for resale.

The following table details the gross notional amounts of commodity options at Dec. 31:
(Amounts in Thousands) (a)(b)
 
2016
 
2015
MMBtu of natural gas
 
255

 
388


(a) 
Amounts are not reflective of net positions in the underlying commodities.
(b) 
Notional amounts for options are included on a gross basis, but are weighted for the probability of exercise.

Consideration of Credit Risk and Concentrations — NSP-Wisconsin continuously monitors the creditworthiness of the counterparties to its interest rate derivatives and commodity derivative contracts prior to settlement, and assesses each counterparty’s ability to perform on the transactions set forth in the contracts.  Given this assessment, as well as an assessment of the impact of NSP-Wisconsin’s own credit risk when determining the fair value of derivative liabilities, the impact of considering credit risk was immaterial to the fair value of unsettled commodity derivatives presented in the consolidated balance sheets.

NSP-Wisconsin employs additional credit risk control mechanisms when appropriate, such as letters of credit, parental guarantees, standardized master netting agreements and termination provisions that allow for offsetting of positive and negative exposures.  Credit exposure is monitored and, when necessary, the activity with a specific counterparty is limited until credit enhancement is provided.

Financial Impact of Qualifying Cash Flow Hedges — The impact of qualifying interest rate cash flow hedges on NSP-Wisconsin’s accumulated other comprehensive loss, included in the consolidated statements of common stockholder’s equity and in the consolidated statements of comprehensive income, is detailed in the following table:
(Thousands of Dollars)
 
2016
 
2015
 
2014
Accumulated other comprehensive loss related to cash flow hedges at Jan. 1
 
$
(209
)
 
$
(285
)
 
$
(361
)
After-tax net realized losses on derivative transactions reclassified into earnings
 
76

 
76

 
76

Accumulated other comprehensive loss related to cash flow hedges at Dec. 31
 
$
(133
)
 
$
(209
)
 
$
(285
)


Pre-tax losses related to interest rate derivatives reclassified from accumulated other comprehensive loss into earnings were $0.1 million for each of the years ended Dec. 31, 2016, 2015 and 2014.

During the years ended Dec. 31, 2016 and 2015 changes in the fair value of natural gas commodity derivatives resulted in net losses of $0.2 million and $0.7 million, recognized as regulatory assets and liabilities. During the year ended Dec. 31, 2014, changes in the fair value of natural gas commodity derivatives resulted in net gains of $0.1 million, recognized as regulatory assets and liabilities. The classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms.

During the years ended Dec. 31, 2016 and 2015, $0.8 million and $1.4 million of natural gas commodity derivatives settlement losses were recognized and immaterial gains were recognized for the year ended Dec. 31, 2014, and were subject to purchased natural gas cost recovery mechanisms, which result in reclassifications of derivative settlement gains and losses out of income to a regulatory asset or liability, as appropriate.

NSP-Wisconsin had no derivative instruments designated as fair value hedges during the years ended Dec. 31, 2016, 2015 and 2014. Therefore, no gains or losses from fair value hedges or related hedged transactions were recognized for these periods.

Recurring Fair Value Measurements — The following table presents for each of the fair value hierarchy levels, NSP-Wisconsin’s derivative assets and liabilities measured at fair value on a recurring basis:
 
 
Dec. 31, 2016
 
 
Fair Value
 
Fair Value
Total
 
Counterparty
Netting (a)
 
 
(Thousands of Dollars)
 
Level 1
 
Level 2
 
Level 3
 
 
 
Total (b)
Current derivative assets
 
 
 
 
 
 
 
 
 
 
 
 
Natural gas commodity
 
$
—

 
$
149

 
$
—

 
$
149

 
$
—

 
$
149

 
 
Dec. 31, 2015
 
 
Fair Value
 
Fair Value
Total
 
Counterparty
Netting (a)
 
 
(Thousands of Dollars)
 
Level 1
 
Level 2
 
Level 3
 
 
 
Total (c)
Current derivative assets
 
 
 
 
 
 
 
 
 
 
 
 
Natural gas commodity
 
$
—

 
$
15

 
$
—

 
$
15

 
$
(11
)
 
$
4

Total current derivative assets
 
$
—

 
$
15

 
$
—

 
$
15

 
$
(11
)
 
$
4

Current derivative liabilities
 
 
 
 
 
 
 
 
 
 
 
 
Natural gas commodity
 
$
—

 
$
194

 
$
—

 
$
194

 
$
(11
)
 
$
183

Total current derivative liabilities
 
$
—

 
$
194

 
$
—

 
$
194

 
$
(11
)
 
$
183


(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, 2016 and 2015.  The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.
(b) 
Included in prepayments and other current assets balance of $3.8 million at Dec. 31, 2016 in the consolidated balance sheets.
(c) 
Included in prepayments and other current assets balance of $2.4 million and other current liabilities balance of $15.1 million at Dec. 31, 2015 in the consolidated balance sheets.

Fair Value of Long-Term Debt

As of Dec. 31, 2016 and 2015, other financial instruments for which the carrying amount did not equal fair value were as follows:
 
 
2016
 
2015
(Thousands of Dollars)
 
Carrying Amount
 
Fair Value
 
Carrying Amount
 
Fair Value
Long-term debt, including current portion (a)
 
$
663,069

 
$
730,284

 
$
662,449

 
$
742,565


(a) 
Amounts reflect the classification of debt issuance costs as a deduction from the carrying amount of the related debt. See Note 2, Accounting Pronouncements for more information on the adoption of ASU No. 2015-03.

The fair value of NSP-Wisconsin’s long-term debt is estimated based on recent trades and observable spreads from benchmark interest rates for similar securities.  The fair value estimates are based on information available to management as of Dec. 31, 2016 and 2015, and given the observability of the inputs to these estimates, the fair values presented for long-term debt have been assigned a Level 2.
v3.6.0.2
Rate Matters (Notes)
 12 Months Ended
Dec. 31, 2016
Public Utilities, General Disclosures [Abstract]  
Rate Matters
Rate Matters

Recently Concluded Regulatory Proceedings — PSCW

Wisconsin 2017 Electric and Gas Rate Case — In April 2016, NSP-Wisconsin filed a request with the PSCW for an increase in annual electric rates of $17.4 million, or 2.4 percent, and an increase in natural gas rates by $4.8 million, or 3.9 percent, effective January 2017.

The electric rate request was for the limited purpose of recovering increases in (1) generation and transmission fixed charges and fuel and purchased power expenses related to the interchange agreement with NSP-Minnesota, and (2) costs associated with forecasted average rate base of $1.188 billion in 2017.

The natural gas rate request was for the limited purpose of recovering expenses related to the ongoing environmental remediation of a former MGP site and adjacent area in Ashland, Wis.

No changes were requested to the capital structure or the 10.0 percent ROE authorized by the PSCW in the 2016 rate case. As part of an agreement with stakeholders to limit the size and scope of the case, NSP-Wisconsin also agreed to an earnings cap, solely for 2017, in which 100 percent of the earnings in excess of the authorized ROE would be refunded to customers.

In December 2016, the PSCW issued an order approving an electric rate increase of approximately $22.5 million, or 3.2 percent, and a natural gas rate increase of $4.8 million, or 3.9 percent. The differences between NSP-Wisconsin’s original electric rate request and the PSCW’s approved electric increase are summarized below:
Electric Rate Request (Millions of Dollars)
 
NSP-Wisconsin Request
 
Final Decision
Rate base investments
 
$
11.0

 
$
7.6

Generation and transmission expenses (excluding fuel and purchased power) (a)
 
6.8

 
6.1

Fuel and purchased power expenses
 
11.0

 
10.7

Subtotal
 
28.8

 
24.4

2015 fuel refund (b)
 
(9.5
)
 
—

Department of Energy settlement refund
 
(1.9
)
 
(1.9
)
Total electric rate increase
 
$
17.4

 
$
22.5


(a) 
Includes Interchange Agreement billings. For financial reporting purposes, these expenses are included in O&M.
(b) 
In July 2016, the PSCW required NSP-Wisconsin to return the 2015 fuel refund directly to customers, rather than using it to offset the proposed 2017 rate increase, as originally proposed by NSP-Wisconsin. This decision, when combined with the increase in forecasted fuel and purchased power expense, effectively increased NSP-Wisconsin’s requested electric rate increase to $29.9 million, or 4.2 percent.
Pending Regulatory Proceedings - MPSC

Michigan 2017 Natural Gas Rate Case — In October 2016, NSP-Wisconsin filed a request with the MPSC to increase base rates for natural gas service by approximately $347 thousand annually, or 6.5 percent. The filing was based on a 2017 forecast test year, a 10.2 percent ROE, an equity ratio of 52.56 percent and a forecasted average rate base of approximately $6.4 million. The primary driver of the requested increase is investment in natural gas distribution infrastructure, mainly in conjunction with NSP-Wisconsin’s Distribution Integrity Management Program (DIMP). NSP-Wisconsin also proposed an Infrastructure Cost Recovery Mechanism (ICRM) rate rider to recover ongoing costs associated with the DIMP. In addition, the filing requested recovery of approximately $129 thousand, or 2.4 percent, through the ICRM, beginning in January 2018.  Under the proposal, the ICRM rider would be adjusted annually. No party sought to intervene in the case. A settlement conference was held in February 2017 at which NSP-Wisconsin reached a verbal settlement with the MPSC staff. The terms and conditions of the agreement are still subject to final documentation and require the approval of the MPSC.

Recently Concluded Regulatory Proceedings — MPUC

Monticello Prudence Investigation — In 2013, NSP-Minnesota completed the Monticello LCM/EPU project. The multi-year project extended the life of the facility and increased the capacity from 600 to 671 MW in 2015. The Monticello LCM/EPU project expenditures were approximately $665 million. Total capitalized costs were approximately $748 million, which includes AFUDC. In 2008, project expenditures were initially estimated at approximately $320 million, excluding AFUDC.

In 2013, the MPUC initiated an investigation to determine whether the final costs for the Monticello LCM/EPU project were prudent.
In March 2015, the MPUC voted to allow for full recovery, including a return, on $415 million of the total plant costs (inclusive of AFUDC), but only allow recovery of the remaining $333 million of costs with no return on this portion of the investment over the remaining life of the plant. As a result of these determinations, Xcel Energy recorded an estimated pre-tax loss of $129 million in the first quarter of 2015, after which the remaining book value of the Monticello project represented the present value of the estimated future cash flows. As NSP-Wisconsin shares in the costs of the Monticello plant through the Interchange Agreement with NSP-Minnesota, the MPUC decision also affects NSP-Wisconsin. NSP-Wisconsin’s portion of the $129 million pre-tax loss, recorded in the first quarter of 2015, was approximately $5 million.

Pending Regulatory Proceedings — FERC

MISO ROE Complaints/ROE Adder — In November 2013, a group of customers filed a complaint at the FERC against MISO TOs, including NSP-Minnesota and NSP-Wisconsin. The complaint argued for a reduction in the ROE in transmission formula rates in the MISO region from 12.38 percent to 9.15 percent, a prohibition on capital structures in excess of 50 percent equity, and the removal of ROE adders (including those for RTO membership and for being an independent transmission company), effective Nov. 12, 2013.

In December 2015, an ALJ initial decision recommended the FERC approve a ROE of 10.32 percent, which the FERC upheld in an order issued on Sept. 28, 2016. This ROE is applicable for the 15 month refund period from Nov. 12, 2013 to Feb. 11, 2015, and prospectively from the date of the FERC order. The total prospective ROE is 10.82 percent, which includes a previously approved 50 basis point adder for RTO membership.

In February 2015, a second complaint seeking to reduce the MISO region ROE from 12.38 percent to 8.67 percent prior to any adder was filed, which the FERC set for hearings, resulting in a second period of potential refund from Feb. 12, 2015 to May 11, 2016. The MPUC, NDPSC, SDPUC and the DOC joined a joint complainant/intervenor initial brief recommending an ROE of approximately 8.81 percent. FERC staff recommended a ROE of 8.78 percent. The MISO TOs recommended a ROE of 10.92 percent. On June 30, 2016, the ALJ recommended a ROE of 9.7 percent, the midpoint of the upper half of the discounted cash flow range. A FERC decision is expected later in 2017.

As of Dec. 31, 2016, NSP-Minnesota has recognized a current liability for the Nov. 12, 2013 to Feb. 11, 2015 complaint period based on the 10.32 percent ROE provided in the FERC order, as well as a current liability representing the best estimate of the final ROE for the second complaint period.
v3.6.0.2
Commitments and Contingencies
 12 Months Ended
Dec. 31, 2016
Commitments and Contingencies Disclosure [Abstract]  
Commitments and Contingencies
Commitments and Contingencies

Commitments

Fuel Contracts — NSP-Wisconsin has entered into various long-term commitments for the purchase and delivery of a significant portion of its current coal and natural gas requirements. These contracts expire in various years between 2017 and 2029. In addition, NSP-Wisconsin is required to pay additional amounts depending on actual quantities shipped under these agreements. As NSP-Wisconsin does not have an automatic electric fuel adjustment clause for Wisconsin retail customers, NSP-Wisconsin utilizes deferred accounting treatment for future rate recovery or refund when fuel costs differ from the amount included in rates by more than two percent on an annual basis, as determined by the PSCW after an opportunity for a hearing and an earnings test based on NSP-Wisconsin’s authorized ROE.

The estimated minimum purchases for NSP-Wisconsin under these contracts as of Dec. 31, 2016 are as follows:
(Millions of Dollars)
 
Coal
 
Natural gas
supply
 
Natural gas
storage and
transportation
2017
 
$
6.9

 
$
10.9

 
$
13.2

2018
 
2.5

 
0.3

 
12.3

2019
 
0.8

 
0.3

 
11.4

2020
 
0.8

 
0.3

 
9.1

2021
 
0.8

 
0.3

 
8.4

Thereafter
 
1.7

 
0.4

 
36.1

Total (a)
 
$
13.5

 
$
12.5

 
$
90.5


(a) 
Excludes additional amounts allocated to NSP-Wisconsin through intercompany charges.

Additional expenditures for fuel and natural gas storage and transportation will be required to meet expected future electric generation and natural gas needs.

Leases — NSP-Wisconsin leases a variety of equipment and facilities used in the normal course of business. These leases, primarily for office space, vehicles, aircraft and power-operated equipment, are accounted for as operating leases. Total expenses under operating lease obligations were approximately $1.2 million, $1.1 million and $1.3 million for 2016, 2015 and 2014, respectively.

Future commitments under operating leases are:
(Millions of Dollars)
 
 
2017
 
$
1.0

2018
 
1.0

2019
 
1.0

2020
 
0.9

2021
 
0.8

Thereafter
 
5.3

Total
 
$
10.0



Variable Interest Entities — The accounting guidance for consolidation of variable interest entities requires enterprises to consider the activities that most significantly impact an entity’s financial performance, and power to direct those activities, when determining whether an enterprise is a variable interest entity’s primary beneficiary.

NSP-Wisconsin has entered into limited partnerships for the construction and operation of affordable rental housing developments which qualify for low-income housing tax credits. NSP-Wisconsin has determined the low-income housing limited partnerships to be variable interest entities primarily due to contractual arrangements within each limited partnership that establish sharing of ongoing voting control and profits and losses that does not consistently align with the partners’ proportional equity ownership. These limited partnerships are designed to qualify for low-income housing tax credits, and NSP-Wisconsin generally receives a larger allocation of the tax credits than the general partners at inception of the arrangements. NSP-Wisconsin has determined that it has the power to direct the activities that most significantly impact these entities’ economic performance, and therefore NSP-Wisconsin consolidates these limited partnerships in its consolidated financial statements.

Equity financing for these entities has been provided by NSP-Wisconsin and the general partner of each limited partnership, and NSP-Wisconsin’s risk of loss is limited to its capital contributions, adjusted for any distributions and its share of undistributed profits and losses; no significant additional financial support has been, or is required to be provided to the limited partnerships by NSP-Wisconsin. Mortgage-backed debt typically comprises the majority of the financing at inception of each limited partnership and is paid over the life of the limited partnership arrangement. Obligations of the limited partnerships are generally secured by the housing properties of each limited partnership, and the creditors of each limited partnership have no significant recourse to NSP-Wisconsin or its subsidiaries. Likewise, the assets of the limited partnerships may only be used to settle obligations of the limited partnerships, and not those of NSP-Wisconsin or its subsidiaries.

Amounts reflected in NSP-Wisconsin’s consolidated balance sheets for low-income housing limited partnerships include the following:
(Thousands of Dollars)
 
Dec. 31, 2016
 
Dec. 31, 2015
Current assets
 
$
375

 
$
377

Property, plant and equipment, net
 
2,025

 
2,199

Other noncurrent assets
 
125

 
127

Total assets
 
$
2,525

 
$
2,703

 
 
 
 
 
Current liabilities
 
$
1,269

 
$
1,246

Mortgages and other long-term debt payable
 
486

 
537

Other noncurrent liabilities
 
54

 
51

Total liabilities
 
$
1,809

 
$
1,834



Joint Operating System — The electric production and transmission system of NSP-Wisconsin is managed as an integrated system with that of NSP-Minnesota, jointly referred to as the NSP System. The electric production and transmission costs of the entire NSP System are shared by NSP-Minnesota and NSP-Wisconsin. A FERC approved agreement between the two companies, called the Interchange Agreement, provides for the sharing of all costs of generation and transmission facilities of the system, including capital costs. Such costs include current and potential obligations of NSP-Minnesota related to its nuclear generating facilities.

On Dec. 31, 2016, NSP-Minnesota’s public liability for claims resulting from any nuclear incident was limited to $13.4 billion under the Price-Anderson amendment to the Atomic Energy Act. NSP-Minnesota had secured $375 million of coverage for its public liability exposure with a pool of insurance companies. The remaining $13.0 billion of exposure was funded by the Secondary Financial Protection Program, available from assessments by the federal government in case of a nuclear accident. On Jan. 1, 2017, the available insurance limit was increased from $375 million to $450 million. This increase in limit occurs periodically and the Price-Anderson amendment to the Atomic Energy Act requires purchasing the full available limit. On Jan. 1, 2017 this $450 million limit was secured from the insurance pool. NSP-Minnesota is subject to assessments of up to $127.3 million per reactor per accident for each of its three licensed reactors, to be applied for public liability arising from a nuclear incident at any licensed nuclear facility in the United States. The maximum funding requirement is $19.0 million per reactor per incident during any one year. These maximum assessment amounts are both subject to inflation adjustment by the NRC and state premium taxes. The NRC’s last adjustment was effective September 2013.

NSP-Minnesota purchases insurance for property damage and site decontamination cleanup costs from Nuclear Electric Insurance Ltd. (NEIL). 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 to the extent that NSP-Minnesota would have no exposure for retroactive premium assessments in case of a single incident under the business interruption and the property damage insurance coverage. However, in each calendar year, NSP-Minnesota could be subject to maximum assessments of approximately $19.8 million for business interruption insurance and $43.0 million for property damage insurance if losses exceed accumulated reserve funds.

Guarantees — NSP-Wisconsin provides a guarantee for payment of customer loans related to NSP-Wisconsin’s farm rewiring program. NSP-Wisconsin’s exposure under the guarantee is based upon the net liability under the agreement. The guarantee issued by NSP-Wisconsin limits the exposure of NSP-Wisconsin to a maximum amount stated in the guarantee. The guarantee contains no recourse provisions and requires no collateral.

The following table presents the guarantee issued and outstanding for NSP-Wisconsin:
(Millions of Dollars)
 
Guarantee
Amount
 
Current
Exposure
 
Term or
Expiration Date
 
Triggering
Event
Guarantee of customer loans for the Farm Rewiring Program(a)
 
$
1.0

 
$
0.1

 
2020
 
(b) 
(a) 
The term of this guarantee expires in 2020, which is the final scheduled repayment date for the loans. As of Dec. 31, 2016, no claims had been made by the lender.
(b) 
The debtor becomes the subject of bankruptcy or other insolvency proceedings.

Environmental Contingencies

NSP-Wisconsin has been or is currently involved with the cleanup of contamination from certain hazardous substances at several sites. In many situations, NSP-Wisconsin believes it will recover some portion of these costs through insurance claims. Additionally, where applicable, NSP-Wisconsin is pursuing, or intends to pursue, recovery from other PRPs and through the regulated rate process. New and changing federal and state environmental mandates can also create added financial liabilities for NSP-Wisconsin, which are normally recovered through the regulated rate process. To the extent any costs are not recovered through the options listed above, NSP-Wisconsin would be required to recognize an expense.

Site Remediation — Various federal and state environmental laws impose liability, without regard to the legality of the original conduct, where hazardous substances or other regulated materials have been released to the environment. NSP-Wisconsin may sometimes pay all or a portion of the cost to remediate sites where past activities of NSP-Wisconsin or other parties have caused environmental contamination. Environmental contingencies could arise from various situations, including sites of former MGPs operated by NSP-Wisconsin, its predecessors, or other entities; and third-party sites, such as landfills, for which NSP-Wisconsin is alleged to be a PRP that sent wastes to that site.

MGP Sites

Ashland MGP Site — NSP-Wisconsin has been named a PRP for contamination at a site in Ashland, Wis. The Ashland/Northern States Power Lakefront Superfund Site (the Site) includes NSP-Wisconsin property, previously operated as a MGP facility (the Upper Bluff), and two other properties: an adjacent city lakeshore park area (Kreher Park); and an area of Lake Superior’s Chequamegon Bay adjoining the park.

In 2012, under a settlement agreement with the EPA, NSP-Wisconsin agreed to remediate the Phase I Project Area (which includes the Upper Bluff and Kreher Park areas of the Site). The current cost estimate for the cleanup of the Phase I Project Area is approximately $72.4 million, of which approximately $56.7 million has been spent.

NSP-Wisconsin performed a wet dredge pilot study in the summer of 2016 and demonstrated that a wet dredge remedy can meet the performance standards for remediation of the Sediments. As a result, the EPA authorized NSP-Wisconsin to extend the wet dredge pilot to additional areas of the Site. In January 2017, under a settlement agreement with the EPA, NSP-Wisconsin agreed to remediate the Phase II Project Area (the Sediments). The settlement agreement was lodged with the U.S. District Court for the Western District of Wisconsin (District Court) in January 2017, and a 30-day public comment period lapsed in February 2017. If the settlement is timely approved by the District Court, NSP-Wisconsin anticipates a full scale wet dredge remedy of the Sediments will be performed in 2017, with restoration activities concluding in 2018.

At Dec. 31, 2016 and 2015, NSP-Wisconsin had recorded a total liability of $64.3 million and $94.4 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 consistently authorized NSP-Wisconsin rate recovery for all remediation costs incurred at the Site. In 2012, the PSCW agreed to allow NSP-Wisconsin to pre-collect certain costs, to amortize costs over a ten-year period and to apply a three percent carrying cost to the unamortized regulatory asset. In April 2016, NSP-Wisconsin filed a limited natural gas rate case for recovery of additional expenses associated with remediating the Site. In December 2016, the PSCW issued a written order approving the requested increase in annual recovery of MGP clean-up costs from $7.6 million in 2016 to $12.4 million in 2017.

Other MGP Sites — NSP-Wisconsin is currently involved in investigating and/or remediating several other MGP sites where regulated materials may have been deposited. NSP-Wisconsin has identified one site where former MGP activities may have resulted in site contamination and is under current investigation. At this MGP site, there are other parties that may have responsibility for some portion of any remediation. NSP-Wisconsin anticipates that the majority of the remediation at this site will continue through at least 2017. NSP-Wisconsin had accrued $0.1 million and $0.2 million for this site at Dec. 31, 2016 and 2015, respectively. There may be insurance recovery and/or recovery from other PRPs that will offset any costs incurred. NSP-Wisconsin anticipates that any amounts spent will be fully recovered from customers.

Environmental Requirements

Water and Waste
Asbestos Removal — Some of NSP-Wisconsin’s facilities contain asbestos. Most asbestos will remain undisturbed until the facilities that contain it are demolished or removed. NSP-Wisconsin has recorded an estimate for final removal of the asbestos as an ARO. It may be necessary to remove some asbestos to perform maintenance or make improvements to other equipment. The cost of removing asbestos as part of other work is not expected to be material and is recorded as incurred as operating expenses for maintenance projects, capital expenditures for construction projects or removal costs for demolition projects.

Federal Clean Water Act (CWA) Effluent Limitations Guidelines (ELG) — In 2015, the EPA issued a final ELG rule for power plants that use coal, natural gas, oil or nuclear materials as fuel and discharge treated effluent to surface waters as well as utility-owned landfills that receive coal combustion residuals. NSP-Wisconsin has reviewed the final rule and is in the process of evaluating whether the costs of compliance could have a material impact on the results of operations, financial position or cash flows. NSP-Wisconsin believes that compliance costs would be recoverable through regulatory mechanisms.

Federal CWA Section 316(b) — Section 316(b) of the federal CWA requires the EPA to regulate cooling water intake structures to assure that these structures reflect the best technology available for minimizing adverse environmental impacts to aquatic species. The EPA published the final 316(b) rule in 2014. The rule prescribes technology for protecting fish that get stuck on plant intake screens (known as impingement) and describes a process for site-specific determinations by each state for sites that must protect the small aquatic organisms that pass through the intake screens into the plant cooling systems (known as entrainment). The timing of compliance with the requirements will vary from plant-to-plant since the new rule does not have a final compliance deadline. Many of the compliance requirements depend on site-specific determinations by state regulators; therefore, the exact cost is somewhat uncertain. NSP-Wisconsin believes at least two plants could be required by state regulators to make improvements to reduce entrainment. NSP-Wisconsin estimates the likely cost for complying with impingement requirements may be incurred between 2017 and 2027 and is approximately $4 million and anticipates these costs will be fully recoverable in rates.

Federal CWA Waters of the United States Rule — In June 2015, the EPA and the U.S. Army Corps of Engineers published a final rule that significantly expands the types of water bodies regulated under the CWA and broadens the scope of waters subject to federal jurisdiction. The expansion of the term “Waters of the U.S.” will subject more utility projects to federal CWA jurisdiction, thereby potentially delaying the siting of new generation projects, pipelines, transmission lines and distribution lines, as well as increasing project costs and expanding permitting and reporting requirements. In October 2015, the U.S. Court of Appeals for the Sixth Circuit issued a nationwide stay of the final rule and subsequently ruled that it, rather than the federal district courts, had jurisdiction over challenges to the rule.  In January 2017, the U.S. Supreme Court agreed to resolve the dispute as to which court should hear challenges to the rule. A ruling is expected by June 2017.

Air
GHG Emission Standard for Existing Sources (Clean Power Plan or CPP) — In 2015, a final rule was published by the EPA for GHG emission standards for existing power plants.  Under the rule, states were required to develop implementation plans by September 2016, with the possibility of an extension to September 2018, or submit to a federal plan for the state prepared by the EPA.  Among other things, the rule requires that state plans include enforceable measures to ensure emissions from existing power plants achieve the EPA’s state-specific interim (2022-2029) and final (2030 and thereafter) emission performance targets.  The CPP was challenged by multiple parties in the D.C. Circuit Court.  In January 2016, the D.C. Circuit Court denied requests to stay the effectiveness of the rule. In February 2016, the U.S. Supreme Court issued an order staying the final CPP rule. In September 2016, the D.C. Circuit Court heard oral arguments in the consolidated challenges to the CPP. The stay will remain in effect until the D.C. Circuit Court reaches its decision and the U.S. Supreme Court either declines to review the lower court’s decision or reaches a decision of its own. During the pendency of the stay, states are not required to submit implementation plans and the EPA will not enforce deadlines or issue a federal plan for any state. All states served by NSP-Wisconsin have suspended formal planning efforts.

NSP-Wisconsin has undertaken a number of initiatives that reduce GHG emissions and respond to state renewable and energy efficiency goals.  The CPP could require additional emission reductions in states in which NSP-Wisconsin operates.  If state plans do not provide credit for the investments NSP-Wisconsin has already made to reduce GHG emissions, or if they require additional initiatives or emission reductions, then their requirements would potentially impose additional substantial costs.  Until NSP-Wisconsin has more information about SIPs or the EPA finalizes its proposed federal plan for the states that do not develop related plans, NSP-Wisconsin cannot predict the costs of compliance with the final rule once it takes effect. NSP-Wisconsin believes compliance costs will be recoverable through regulatory mechanisms.  If NSP-Wisconsin’s regulators do not allow recovery of all or a part of the cost of capital investment or the O&M costs incurred to comply with the CPP or cost recovery is not provided in a timely manner, it could have a material impact on results of operations, financial position or cash flows.

CSAPR — CSAPR addresses long range transport of PM and ozone by requiring reductions in SO2 and NOx from utilities in the eastern half of the United States, including Wisconsin, using an emissions trading program.

CSAPR was adopted to address interstate emissions impacting downwind states’ attainment of the 1997 ozone NAAQS and the 1997 and 2006 particulate NAAQS. As the EPA revises NAAQS, it will consider whether to make any further reductions to CSAPR emission budgets and whether to change which states are included in the emissions trading program. In December 2015, the EPA proposed adjustments to CSAPR emission budgets which address attainment of the more stringent 2008 ozone NAAQS. The EPA adopted a final rule in September 2016 for the ozone season emission budget for NOx which did not materially impact NSP-Wisconsin.

Revisions to the NAAQS for Ozone — In 2015, the EPA revised the NAAQS for ozone by lowering the eight-hour standard from 75 parts per billion (ppb) to 70 ppb. Current monitored air quality concentrations in areas of Wisconsin, where NSP-Wisconsin operates, are below the new standard. Therefore, NSP-Wisconsin does not expect a material impact on results of operations, financial position or cash flows.

Asset Retirement Obligations

Recorded AROs — AROs have been recorded for property related to the following: electric production (steam, other and hydro), electric distribution and transmission, natural gas distribution, and general property. The electric production obligations include asbestos, ash-containment facilities, storage tanks and control panels. The asbestos recognition associated with electric production includes certain specific plants. AROs also have been recorded for NSP-Wisconsin steam production related to ash-containment facilities such as bottom ash ponds, evaporation ponds and solid waste landfills.

NSP-Wisconsin has recognized an ARO for the retirement costs of natural gas mains and lines and for the removal of electric transmission and distribution equipment, which consists of many small potential obligations associated with PCBs, mineral oil, storage tanks, lithium batteries, mercury and street lighting lamps. The electric and common general AROs include small obligations primarily related to storage tanks.

In April 2015, the EPA published the final rule regulating the management and disposal of coal combustion byproducts (e.g., coal ash) as a nonhazardous waste to the Federal Register. The rule became effective in October 2015. No cash flow revisions were necessary, as a result of the final rule, as of Dec. 31, 2015.

A reconciliation of NSP-Wisconsin’s AROs for the years ended Dec. 31, 2016 and 2015 is as follows:
(Thousands of Dollars)
 
Beginning Balance
Jan. 1, 2016
 
Liabilities Settled
 
Accretion
 
Cash Flow Revisions
 
Ending Balance
   Dec. 31, 2016 (a)
Electric plant
 
 
 
 
 
 
 
 
 
 
Steam production asbestos
 
$
2,145

 
$
—

 
$
49

 
$
—

 
$
2,194

Steam production ash containment
 
617

 
—

 
18

 
(183
)
 
452

Electric distribution
 
72

 
—

 
3

 
(43
)
 
32

Other
 
391

 
(29
)
 
14

 
—

 
376

Natural gas plant
 
 
 
 
 
 
 
 
 
 
Gas distribution
 
6,367

 
—

 
256

 
1,670

 
8,293

Common and other property
 
 
 
 
 
 
 
 
 
 
Common miscellaneous
 
95

 
—

 
2

 
(52
)
 
45

Total liability (b)
 
$
9,687

 
$
(29
)
 
$
342

 
$
1,392

 
$
11,392


(a) 
There were no ARO liabilities recognized during the year ended Dec. 31, 2016.
(b) 
Included in other long-term liabilities balance in the consolidated balance sheet.

(Thousands of Dollars)
 
Beginning Balance
Jan. 1, 2015
 
Accretion
 
Cash Flow
   Revisions
 
Ending Balance
    Dec. 31, 2015 (a)
Electric plant
 
 
 
 
 
 
 
 
Steam production asbestos
 
$
2,049

 
$
45

 
$
51

 
$
2,145

Steam production ash containment
 
374

 
14

 
229

 
617

Electric distribution
 
37

 
1

 
34

 
72

Other
 
412

 
15

 
(36
)
 
391

Natural gas plant
 
 
 
 
 
 
 
 
Gas distribution
 
6,127

 
240

 
—

 
6,367

Common and other property
 
 
 
 
 
 
 
 
Common miscellaneous
 
91

 
4

 
—

 
95

Total liability (b)
 
$
9,090

 
$
319

 
$
278

 
$
9,687

 
(a) 
There were no ARO liabilities recognized or settled during the year ended Dec. 31, 2015.
(b) 
Included in other long-term liabilities balance in the consolidated balance sheet.


Indeterminate AROs — Outside of the known and recorded asbestos AROs, other plants or buildings may contain asbestos due to the age of many of NSP-Wisconsin’s facilities, but no confirmation or measurement of the amount of asbestos or cost of removal could be determined as of Dec. 31, 2016. Therefore, an ARO has not been recorded for these facilities.

Removal Costs — NSP-Wisconsin records a regulatory liability for the plant removal costs of generation, transmission and distribution facilities that are recovered currently in rates. Generally, the accrual of future non-ARO removal obligations is not required. However, long-standing ratemaking practices approved by applicable state and federal regulatory commissions have allowed provisions for such costs in historical depreciation rates. These removal costs have accumulated over a number of years based on varying rates as authorized by the appropriate regulatory entities. Given the long time periods over which the amounts were accrued and the changing of rates over time, NSP-Wisconsin has estimated the amount of removal costs accumulated through historic depreciation expense based on current factors used in the existing depreciation rates. Accordingly, the recorded amounts of estimated future removal costs are considered regulatory liabilities. Removal costs as of Dec. 31, 2016 and 2015 were $140 million and $132 million, respectively.

Legal Contingencies

NSP-Wisconsin is involved in various litigation matters that are being defended and handled in the ordinary course of business. The assessment of whether a loss is probable or is a reasonable possibility, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. Management maintains accruals for such losses that are probable of being incurred and subject to reasonable estimation. Management is sometimes unable to estimate an amount or range of a reasonably possible loss in certain situations, including but not limited to when (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss. For current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on NSP-Wisconsin’s financial statements. Unless otherwise required by GAAP, legal fees are expensed as incurred.

Gas Trading Litigation — e prime, inc. (e prime) is a wholly owned subsidiary of Xcel Energy.  e prime was in the business of natural gas trading and marketing, but has not engaged in natural gas trading or marketing activities since 2003.  Thirteen lawsuits were commenced against e prime and Xcel Energy (and NSP-Wisconsin, in two instances) between 2003 and 2009 alleging fraud and anticompetitive activities in conspiring to restrain the trade of natural gas and manipulate natural gas prices.

The cases were consolidated in U.S. District Court in Nevada. Five of the cases have since been settled and seven have been dismissed. One multi-district litigation (MDL) matter remains and it consists of a Colorado class (Breckenridge), a Wisconsin class (NSP-Wisconsin), a Kansas class, and two other cases identified as “Sinclair Oil” and “Farmland.” In November 2016, the MDL judge dismissed e prime and Xcel Energy from the Farmland lawsuit. Motions for summary judgment have been filed by defendants, including e prime, in all of the remaining lawsuits. Defendants have also filed briefs opposing plaintiffs’ motion for class certification.

The majority of the motions filed were argued to the court in January 2017. It is uncertain when the court will render a decision concerning these motions. Xcel Energy, NSP-Wisconsin and e prime have concluded that a loss is remote.

Other Contingencies

See Note 10 for further discussion.
v3.6.0.2
Regulatory Assets and Liabilities
 12 Months Ended
Dec. 31, 2016
Regulatory Assets and Liabilities Disclosure [Abstract]  
Regulatory Assets and Liabilities
12.
Regulatory Assets and Liabilities

NSP-Wisconsin’s consolidated financial statements are prepared in accordance with the applicable accounting guidance, as discussed in Note 1.  Under this guidance, regulatory assets and liabilities are created for amounts that regulators may allow to be collected, or may require to be paid back to customers in future electric and natural gas rates.  Any portion of the business that is not rate regulated cannot establish regulatory assets and liabilities.  If changes in the utility industry or the business of NSP-Wisconsin no longer allow for the application of regulatory accounting guidance under GAAP, NSP-Wisconsin would be required to recognize the write-off of regulatory assets and liabilities in net income or OCI.

The components of regulatory assets shown on the consolidated balance sheets of NSP-Wisconsin at Dec. 31, 2016 and 2015 are:
(Thousands of Dollars)
 
See Note(s)
 
Remaining
Amortization Period
 
Dec. 31, 2016
 
Dec. 31, 2015
Regulatory Assets
 
 
 
 
 
Current
 
Noncurrent
 
Current
 
Noncurrent
Environmental remediation costs
 
1, 11
 
Various
 
$
10,669

 
$
148,880

 
$
6,702

 
$
160,699

Pension and retiree medical obligations (a)
 
7
 
Various
 
5,989

 
93,160

 
6,415

 
86,778

Recoverable deferred taxes on AFUDC recorded in plant
 
1
 
Plant lives
 
—

 
22,345

 
—

 
20,586

State commission adjustments
 
1
 
Plant lives
 
703

 
14,008

 
724

 
12,945

Losses on reacquired debt
 
4
 
Term of related debt
 
801

 
3,333

 
803

 
4,134

Deferred income tax adjustment
 
1, 6
 
Typically plant lives
 
—

 
2,078

 
—

 
2,250

Other
 
 
 
Various
 
—

 
2,384

 
1,502

 
1,804

Total regulatory assets
 
 
 
 
 
$
18,162

 
$
286,188

 
$
16,146

 
$
289,196


(a) 
Includes the non-qualified pension plan.

The components of regulatory liabilities shown on the consolidated balance sheets of NSP-Wisconsin at Dec. 31, 2016 and 2015 are:
(Thousands of Dollars)
 
See Note(s)
 
Remaining
Amortization Period
 
Dec. 31, 2016
 
Dec. 31, 2015
Regulatory Liabilities
 
 
 
 
 
Current
 
Noncurrent
 
Current
 
Noncurrent
Plant removal costs
 
11
 
Plant lives
 
$
—

 
$
139,735

 
$
—

 
$
132,311

Investment tax credit deferrals
 
1, 6
 
Various
 
—

 
8,342

 
—

 
8,869

Deferred electric production and natural gas costs
 
1
 
Less than one year
 
11,377

 
—

 
9,386

 
—

DOE settlement
 
11
 
Less than one year
 
4,822

 
—

 
1,996

 
—

Conservation programs
 
1
 
Less than one year
 
1,122

 
—

 
339

 
—

Other
 
 
 
Various
 
107

 
112

 
60

 
109

Total regulatory liabilities
 
 
 
 
 
$
17,428

 
$
148,189

 
$
11,781

 
$
141,289



At Dec. 31, 2016 and 2015, approximately $0 million and $1 million of NSP-Wisconsin’s regulatory assets represented past expenditures not currently earning a return, respectively.  This amount primarily includes Monticello EPU costs and recoverable purchased natural gas and electric energy costs.
v3.6.0.2
Other Comprehensive Income
 12 Months Ended
Dec. 31, 2016
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, 2016 and 2015 were as follows:
 
 
Gains and Losses on Cash Flow Hedges
(Thousands of Dollars)
 
Year Ended Dec. 31, 2016
 
Year Ended Dec. 31, 2015
Accumulated other comprehensive loss at Jan. 1
 
$
(209
)
 
$
(285
)
Losses reclassified from net accumulated other comprehensive loss
 
76

 
76

Net current period other comprehensive income
 
76

 
76

Accumulated other comprehensive loss at Dec. 31
 
$
(133
)
 
$
(209
)


Reclassifications from accumulated other comprehensive loss for the years ended Dec. 31, 2016 and 2015 were as follows:
 
 
Amounts Reclassified from Accumulated
Other Comprehensive Loss
 
(Thousands of Dollars)
 
Year Ended Dec. 31, 2016
 
Year Ended Dec. 31, 2015
 
Losses on cash flow hedges:
 
 
 
 
 
Interest rate derivatives
 
$
127

(a) 
$
127

(a) 
Total, pre-tax
 
127

 
127

 
Tax benefit
 
(51
)
 
(51
)
 
Total amounts reclassified, net of tax
 
$
76

 
$
76

 

(a) 
Included in interest charges.
v3.6.0.2
Segments and Related Information
 12 Months Ended
Dec. 31, 2016
Segment Reporting [Abstract]  
Segment Information
Segments and Related Information

Operating results from the regulated electric utility and regulated natural gas utility are each separately and regularly reviewed by NSP-Wisconsin’s chief operating decision maker.  NSP-Wisconsin evaluates performance based on profit or loss generated from the product or service provided.  These segments are managed separately because the revenue streams are dependent upon regulated rate recovery, which is separately determined for each segment.

NSP-Wisconsin has the following reportable segments: regulated electric utility, regulated natural gas utility and all other.

•
NSP-Wisconsin’s regulated electric utility segment generates electricity which is transmitted and distributed in Wisconsin and Michigan.
•
NSP-Wisconsin’s regulated natural gas utility segment purchases, transports, stores and distributes natural gas in portions of Wisconsin and Michigan.
•
Revenues from operating segments not included above are below the necessary quantitative thresholds and are therefore included in the all other category.  Those primarily include investments in rental housing projects that qualify for low-income housing tax credits.

Asset and capital expenditure information is not provided for NSP-Wisconsin’s reportable segments because as an integrated electric and natural gas utility, NSP-Wisconsin operates significant assets that are not dedicated to a specific business segment, and reporting assets and capital expenditures by business segment would require arbitrary and potentially misleading allocations which may not necessarily reflect the assets that would be required for the operation of the business segments on a stand-alone basis.

To report income from operations for regulated electric and regulated natural gas utility segments, the majority of costs are directly assigned to each segment. However, some costs, such as common depreciation, common O&M expenses and interest expense are allocated based on cost causation allocators. A general allocator is used for certain general and administrative expenses, including office supplies, rent, property insurance and general advertising.

The accounting policies of the segments are the same as those described in Note 1.

(Thousands of Dollars)
 
Regulated
Electric
 
Regulated
Natural Gas
 
All Other
 
Reconciling
Eliminations
 
Consolidated
Total
2016
 
 
 
 
 
 
 
 
 
 
Operating revenues (a)
 
$
849,946

 
$
106,157

 
$
1,130

 
$
—

 
$
957,233

Intersegment revenues
 
397

 
487

 
—

 
(884
)
 
—

Total revenues
 
$
850,343

 
$
106,644

 
$
1,130

 
$
(884
)
 
$
957,233

 
 
 
 
 
 
 
 
 
 
 
Depreciation and amortization
 
$
81,299

 
$
16,794

 
$
201

 
$
—

 
$
98,294

Interest charges and financing costs
 
29,749

 
2,855

 
25

 
—

 
32,629

Income tax expense (benefit)
 
40,547

 
2,445

 
(90
)
 
—

 
42,902

Net income (loss)
 
65,002

 
4,503

 
(370
)
 
—

 
69,135

(Thousands of Dollars)
 
Regulated
Electric
 
Regulated
Natural Gas
 
All Other
 
Reconciling
Eliminations
 
Consolidated
Total
2015
 
 
 
 
 
 
 
 
 
 
Operating revenues (a)
 
$
834,998

 
$
120,147

 
$
1,396

 
$
—

 
$
956,541

Intersegment revenues
 
419

 
498

 
—

 
(917
)
 
—

Total revenues
 
$
835,417

 
$
120,645

 
$
1,396

 
$
(917
)
 
$
956,541

 
 
 
 
 
 
 
 
 
 
 
Depreciation and amortization
 
$
77,036

 
$
14,034

 
$
175

 
$
—

 
$
91,245

Interest charges and financing costs
 
26,494

 
2,637

 
90

 
—

 
29,221

Income tax expense
 
40,654

 
2,501

 
1,083

 
—

 
44,238

Net income
 
69,398

 
4,862

 
376

 
—

 
74,636

(Thousands of Dollars)
 
Regulated
Electric
 
Regulated
Natural Gas
 
All Other
 
Reconciling
Eliminations
 
Consolidated
Total
2014
 
 
 
 
 
 
 
 
 
 
Operating revenues (a)
 
$
829,748

 
$
169,629

 
$
1,085

 
$
—

 
$
1,000,462

Intersegment revenues
 
497

 
4,885

 
—

 
(5,382
)
 
—

Total revenues
 
$
830,245

 
$
174,514

 
$
1,085

 
$
(5,382
)
 
$
1,000,462

 
 
 
 
 
 
 
 
 
 
 
Depreciation and amortization
 
$
65,978

 
$
13,501

 
$
175

 
$
—

 
$
79,654

Interest charges and financing costs
 
23,448

 
2,358

 
107

 
—

 
25,913

Income tax expense (benefit)
 
39,621

 
5,993

 
(3,211
)
 
—

 
42,403

Net income
 
59,060

 
8,714

 
2,868

 
—

 
70,642


(a) 
Operating revenues include $170 million, $163 million and $145 million of intercompany revenue for the years ended Dec. 31, 2016, 2015 and 2014 respectively. See Note 15 for further discussion of related party transactions by operating segment.
v3.6.0.2
Related Party Transactions
 12 Months Ended
Dec. 31, 2016
Related Party Transactions [Abstract]  
Related Party Transactions
Related Party Transactions

Xcel Energy Services Inc. provides management, administrative and other services for the subsidiaries of Xcel Energy Inc., including NSP-Wisconsin. The services are provided and billed to each subsidiary in accordance with service agreements executed by each subsidiary. NSP-Wisconsin uses services provided by Xcel Energy Services Inc. whenever possible. Costs are charged directly to the subsidiary and are allocated if they cannot be directly assigned.

The electric production and transmission costs of the entire NSP System are shared by NSP-Minnesota and NSP-Wisconsin. The Interchange Agreement provides for the sharing of all costs of generation and transmission facilities of the system, including capital costs.

The table below contains significant affiliate transactions among the companies and related parties including billings under the Interchange Agreement for the years ended Dec. 31:
(Thousands of Dollars)
 
2016
 
2015
 
2014
Operating revenues:
 
 
 
 
 
 
Electric
 
$
170,483

 
$
163,255

 
$
145,102

Operating expenses:
 
 
 
 
 
 
Purchased power (a)
 
413,615

 
419,028

 
430,666

Transmission expense
 
61,920

 
54,070

 
43,876

Natural gas purchased for resale
 
41

 
45

 
90

Other operating expenses — paid to Xcel Energy Services Inc.
 
106,454

 
93,890

 
84,224

Interest expense
 
4

 
2

 
30


(a) 
Pursuant to orders issued by the PSCW in December 2013 and February 2014, the 2014 amounts do not reflect $5.2 million of purchased power expenses deferred as a regulatory asset and $11.0 million of transmission costs deferred as a regulatory liability billed to NSP-Wisconsin through the Interchange Agreement from NSP-Minnesota.

Accounts receivable and payable with affiliates at Dec. 31 were:
 
 
2016
 
2015
(Thousands of Dollars)
 
Accounts
Receivable
 
Accounts
Payable
 
Accounts
Receivable
 
Accounts
Payable
NSP-Minnesota
 
$
—

 
$
18,567

 
$
—

 
$
18,268

PSCo
 
—

 
974

 
—

 
71

SPS
 
333

 
—

 
71

 
—

Other subsidiaries of Xcel Energy Inc.
 
—

 
9,496

 
—

 
6,199

 
 
$
333

 
$
29,037

 
$
71

 
$
24,538
v3.6.0.2
Summarized Quarterly Financial Data (Unaudited)
 12 Months Ended
Dec. 31, 2016
Quarterly Financial Information Disclosure [Abstract]  
Summarized Quarterly Financial Data (Unaudited)
Summarized Quarterly Financial Data (Unaudited)
 
 
Quarter Ended
(Thousands of Dollars)
 
March 31, 2016
 
June 30, 2016
 
Sept. 30, 2016
 
Dec. 31, 2016
Operating revenues
 
$
254,850

 
$
219,173

 
$
246,144

 
$
237,066

Operating income
 
35,448

 
27,778

 
46,342

 
30,360

Net income
 
17,631

 
12,625

 
24,221

 
14,658

 
 
Quarter Ended
(Thousands of Dollars)
 
March 31, 2015
 
June 30, 2015
 
Sept. 30, 2015
 
Dec. 31, 2015
Operating revenues
 
$
273,960

 
$
216,813

 
$
236,161

 
$
229,607

Operating income
 
39,549

 
25,069

 
47,532

 
27,809

Net income
 
22,267

 
12,512

 
26,232

 
13,625
v3.6.0.2
Schedule II, Valuation and Qualifying Accounts
 12 Months Ended
Dec. 31, 2016
Valuation and Qualifying Accounts [Abstract]  
Schedule II, Valuation and Qualifying Accounts
NSP-WISCONSIN AND SUBSIDIARIES
VALUATION AND QUALIFYING ACCOUNTS
YEARS ENDED DEC. 31, 2016, 2015 AND 2014
(amounts in thousands)
 
 
 
Additions
 
 
 
 
 
Balance at
Jan. 1
 
Charged to Costs and Expenses
 
Charged to Other
Accounts(a)
 
Deductions from 
Reserves(b)
 
Balance at
Dec. 31
Allowance for bad debts:
 
 
 
 
 
 
 
 
 
2016
$
5,128

 
$
3,730

 
$
1,008

 
$
5,001

 
$
4,865

2015
5,821

 
3,947

 
1,161

 
5,801

 
5,128

2014
4,911

 
4,431

 
1,269

 
4,790

 
5,821


(a) 
Recovery of amounts previously written off.
(b) 
Deductions relate primarily to bad debt write-offs.
v3.6.0.2
Summary of Significant Accounting Policies (Policies)
 12 Months Ended
Dec. 31, 2016
Accounting Policies [Abstract]  
Business and System of Accounts
Business and System of Accounts — NSP-Wisconsin is engaged in the regulated generation, transmission, distribution and sale of electricity and in the regulated purchase, transportation, distribution and sale of natural gas.  NSP-Wisconsin’s consolidated financial statements and disclosures are presented in accordance with GAAP.  All of NSP-Wisconsin’s underlying accounting records also conform to the FERC uniform system of accounts or to systems required by various state regulatory commissions, which are the same in all material respects.
Principles of Consolidation
Principles of Consolidation — NSP-Wisconsin’s consolidated financial statements include its wholly-owned subsidiaries and variable interest entities for which it is the primary beneficiary.  In the consolidation process, all intercompany transactions and balances are eliminated. NSP-Wisconsin has investments in certain transmission facilities jointly owned with nonaffiliated utilities. NSP-Wisconsin’s proportionate share of jointly owned facilities is recorded as property, plant and equipment on the consolidated balance sheets and NSP-Wisconsin’s proportionate share of the operating costs associated with these facilities is included in its consolidated statements of income. See Note 5 for further discussion of jointly owned transmission facilities and related ownership percentages.

NSP-Wisconsin evaluates its arrangements and contracts with other entities to determine if the other party is a variable interest entity, if NSP-Wisconsin has a variable interest and if NSP-Wisconsin is the primary beneficiary.  NSP-Wisconsin follows accounting guidance for variable interest entities which requires consideration of the activities that most significantly impact an entity’s financial performance and power to direct those activities, when determining whether NSP-Wisconsin is a variable interest entity’s primary beneficiary. See Note 11 for further discussion of variable interest entities.
Use of Estimates
Use of Estimates — In recording transactions and balances resulting from business operations, NSP-Wisconsin uses estimates based on the best information available. Estimates are used for such items as plant depreciable lives or potential disallowances, AROs, certain regulatory assets and liabilities, tax provisions, uncollectible amounts, environmental costs, unbilled revenues, jurisdictional fuel and energy cost allocations and actuarially determined benefit costs. The recorded estimates are revised when better information becomes available or when actual amounts can be determined. Those revisions can affect operating results.
Regulatory Accounting
Regulatory Accounting — NSP-Wisconsin accounts for certain income and expense items in accordance with accounting guidance for regulated operations. Under this guidance:

•
Certain costs, which would otherwise be charged to expense or OCI, are deferred as regulatory assets based on the expected ability to recover the costs in future rates; and
•
Certain credits, which would otherwise be reflected as income or OCI, are deferred as regulatory liabilities based on the expectation the amounts will be returned to customers in future rates, or because the amounts were collected in rates prior to the costs being incurred.

Estimates of recovering deferred costs and returning deferred credits are based on specific ratemaking decisions or precedent for each item. Regulatory assets and liabilities are amortized consistent with the treatment in the rate setting process.

If restructuring or other changes in the regulatory environment occur, NSP-Wisconsin may no longer be eligible to apply this accounting treatment, and may be required to eliminate regulatory assets and liabilities from its balance sheets.  Such changes could have a material effect on NSP-Wisconsin’s financial condition, results of operations and cash flows.  See Note 12 for further discussion of regulatory assets and liabilities.
Revenue Recognition
Revenue Recognition — Revenues related to the sale of energy are generally recorded when service is rendered or energy is delivered to customers. However, the determination of the energy sales to individual customers is based on the reading of their meter, which occurs on a systematic basis throughout the month.  At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated and the corresponding unbilled revenue is recognized.  NSP-Wisconsin presents its revenues net of any excise or other fiduciary-type taxes or fees.

NSP-Wisconsin has various rate-adjustment mechanisms in place that provide for the recovery of purchased natural gas, electric fuel and purchased energy costs.  These cost-adjustment tariffs may increase or decrease the level of revenue collected from customers and are revised periodically, for differences between the total amount collected under the clauses and the costs incurred.  When applicable, under governing regulatory commission rate orders, fuel cost over-recoveries (the excess of fuel revenue billed to customers over fuel costs incurred) are deferred as regulatory liabilities and under-recoveries (the excess of fuel costs incurred over fuel revenues billed to customers) are deferred as regulatory assets. Under Wisconsin rules, NSP-Wisconsin must submit a forward looking fuel cost plan annually for approval by the PSCW. The rules also allow for deferral of any under-collection or over-collection of fuel costs in excess of a two percent annual tolerance band, for future rate recovery or refund, subject to PSCW approval.
Conservation Programs
Conservation Programs — NSP-Wisconsin participates in and funds conservation programs in its retail jurisdictions to assist customers in conserving energy and reducing peak demand on the electric and natural gas systems.  NSP-Wisconsin recovers approved conservation program costs in base rate revenue.
Property, Plant and Equipment and Depreciation
Property, Plant and Equipment and Depreciation — Property, plant and equipment is stated at original cost. The cost of plant includes direct labor and materials, contracted work, overhead costs and AFUDC. The cost of plant retired is charged to accumulated depreciation and amortization. Amounts recovered in rates for future removal costs are recorded as regulatory liabilities. Significant additions or improvements extending asset lives are capitalized, while repairs and maintenance costs are charged to expense as incurred. Maintenance and replacement of items determined to be less than a unit of property are charged to operating expenses as incurred. Planned major maintenance activities are charged to operating expense unless the cost represents the acquisition of an additional unit of property or the replacement of an existing unit of property.  Property, plant and equipment also includes costs associated with property held for future use.  The depreciable lives of certain plant assets are reviewed annually and revised, if appropriate.

Property, plant and equipment is tested for impairment when it is determined that the carrying value of the assets may not be recoverable. A loss is recognized in the current period if it becomes probable that part of a cost of a plant under construction or recently completed plant will be disallowed for recovery from customers and a reasonable estimate of the disallowance can be made. For investments in property, plant and equipment that are abandoned and not expected to go into service, incurred costs and related deferred tax amounts are compared to the discounted estimated future rate recovery, and a loss is recognized, if necessary.

NSP-Wisconsin records depreciation expense related to its plant using the straight-line method over the plant’s useful life. Actuarial life studies are performed and submitted to the state and federal commissions for review.  Upon acceptance by the various commissions, the resulting lives and net salvage rates are used to calculate depreciation.  Depreciation expense, expressed as a percentage of average depreciable property, was approximately 3.3, 3.4 and 3.3 percent for the years ended Dec. 31, 2016, 2015 and 2014, respectively.
Leases
Leases — NSP-Wisconsin evaluates a variety of contracts for lease classification at inception, including rental arrangements for office space, vehicles and equipment.  Contracts determined to contain a lease because of per unit pricing that is other than fixed or market price, terms regarding the use of a particular asset, and other factors are evaluated further to determine if the arrangement is a capital lease. See Note 11 for further discussion of leases.
AFUDC
AFUDC — AFUDC represents the cost of capital used to finance utility construction activity. AFUDC is computed by applying a composite financing rate to qualified CWIP. The amount of AFUDC capitalized as a utility construction cost is credited to nonoperating income (for equity capital) and interest charges (for debt capital). AFUDC amounts capitalized are included in NSP-Wisconsin’s rate base for establishing utility service rates.

Generally, AFUDC costs are recovered from customers as the related property is depreciated.  However, in some cases, the PSCW has allowed an AFUDC calculation greater than the FERC-defined AFUDC rate, resulting in higher recognition of AFUDC. In some cases for certain transmission projects, the FERC has approved a more current recovery of the cost of capital associated with large capital projects, resulting in a lower recognition of AFUDC.
Asset Retirement Obligations
AROs — NSP-Wisconsin accounts for AROs under accounting guidance that requires a liability for the fair value of an ARO to be recognized in the period in which it is incurred if it can be reasonably estimated, with the offsetting associated asset retirement costs capitalized as a long-lived asset. The liability is generally increased over time by applying the effective interest method of accretion, and the capitalized costs are depreciated over the useful life of the long-lived asset. Changes resulting from revisions to the timing or amount of expected asset retirement cash flows are recognized as an increase or a decrease in the ARO. NSP-Wisconsin also recovers through rates certain future plant removal costs in addition to AROs. The accumulated removal costs for these obligations are reflected in the balance sheets as a regulatory liability. See Note 11 for further discussion of AROs.
Income Taxes
Income Taxes — NSP-Wisconsin accounts for income taxes using the asset and liability method, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the financial statements. NSP-Wisconsin defers income taxes for all temporary differences between pretax financial and taxable income, and between the book and tax bases of assets and liabilities.  NSP-Wisconsin uses the tax rates that are scheduled to be in effect when the temporary differences are expected to reverse. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period that includes the enactment date.

Deferred tax assets are reduced by a valuation allowance if it is more likely than not that some portion or all of the deferred tax asset will not be realized. In making such a determination, all available evidence is considered, including scheduled reversals of deferred tax liabilities, projected future taxable income, tax planning strategies and recent financial operations.

Due to the effects of past regulatory practices, when deferred taxes were not required to be recorded due to the use of flow through accounting for ratemaking purposes, the reversal of some temporary differences are accounted for as current income tax expense. Tax credits are recorded when earned unless there is a requirement to defer the benefit and amortize it over the book depreciable lives of the related property. The requirement to defer and amortize tax credits only applies to federal ITCs related to public utility property. Utility rate regulation also has resulted in the recognition of certain regulatory assets and liabilities related to income taxes, which are summarized in Note 12.

NSP-Wisconsin follows the applicable accounting guidance to measure and disclose uncertain tax positions that it has taken or expects to take in its income tax returns.  NSP-Wisconsin recognizes a tax position in its consolidated financial statements when it is more likely than not that the position will be sustained upon examination based on the technical merits of the position.  Recognition of changes in uncertain tax positions are reflected as a component of income tax.

NSP-Wisconsin reports interest and penalties related to income taxes within the other income and interest charges sections in the consolidated statements of income.

Xcel Energy Inc. and its subsidiaries, including NSP-Wisconsin, file consolidated federal income tax returns as well as combined or separate state income tax returns.  Federal income taxes paid by Xcel Energy Inc. are allocated to Xcel Energy Inc.’s subsidiaries based on separate company computations of tax.  A similar allocation is made for state income taxes paid by Xcel Energy Inc. in connection with combined state filings. Xcel Energy Inc. also allocates its own income tax benefits to its direct subsidiaries which are recorded directly in equity by the subsidiaries based on the relative positive tax liabilities of the subsidiaries.

See Note 6 for further discussion of income taxes.
Types of and Accounting for Derivative Instruments
Types of and Accounting for Derivative Instruments — NSP-Wisconsin uses derivative instruments in connection with its utility commodity price and interest rate activities, including forward contracts, futures, swaps and options.  All derivative instruments not designated and qualifying for the normal purchases and normal sales exception, as defined by the accounting guidance for derivatives and hedging, are recorded on the consolidated balance sheets at fair value as derivative instruments.  This includes certain instruments used to mitigate market risk for the utility operations.  The classification of changes in fair value for those derivative instruments is dependent on the designation of a qualifying hedging relationship.  Changes in fair value of derivative instruments not designated in a qualifying hedging relationship are reflected in current earnings or as a regulatory asset or liability.  The classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms.

Interest rate hedging transactions are recorded as a component of interest expense.  NSP-Wisconsin is allowed to recover in electric or natural gas rates the costs of certain financial instruments purchased to reduce commodity cost volatility.  For further information on derivatives entered to mitigate commodity price risk on behalf of electric and natural gas customers, see Note 9.

Cash Flow Hedges — Certain qualifying hedging relationships are designated as a hedge of a forecasted transaction or future cash flow (cash flow hedge). Changes in the fair value of a derivative designated as a cash flow hedge, to the extent effective, are included in OCI, or deferred as a regulatory asset or liability based on recovery mechanisms until earnings are affected by the hedged transaction.

Normal Purchases and Normal Sales — NSP-Wisconsin enters into contracts for the purchase and sale of commodities for use in its business operations. Derivatives and hedging accounting guidance requires a company to evaluate these contracts to determine whether the contracts are derivatives.  Certain contracts that meet the definition of a derivative may be exempted from derivative accounting if designated as normal purchases or normal sales.

NSP-Wisconsin evaluates all of its contracts at inception to determine if they are derivatives and if they meet the normal purchases and normal sales designation requirements.  See Note 9 for further discussion of NSP-Wisconsin’s risk management and derivative activities.
Fair Value Measurements
Fair Value Measurements — NSP-Wisconsin presents cash equivalents, interest rate derivatives and commodity derivatives at estimated fair values in its consolidated financial statements.  Cash equivalents are recorded at cost plus accrued interest; money market funds are measured using quoted NAVs.  For interest rate derivatives, quoted prices based primarily on observable market interest rate curves are used as a primary input to establish fair value.  For commodity derivatives, the most observable inputs available are generally used to determine the fair value of each contract.  In the absence of a quoted price for an identical contract in an active market, NSP-Wisconsin may use quoted prices for similar contracts, or internally prepared valuation models to determine fair value. See Note 9 for further discussion.
Cash and Cash Equivalents
Cash and Cash Equivalents — NSP-Wisconsin considers investments in certain instruments, including commercial paper and money market funds, with a remaining maturity of three months or less at the time of purchase, to be cash equivalents.
Accounts Receivable and Allowance for Bad Debts
Accounts Receivable and Allowance for Bad Debts — Accounts receivable are stated at the actual billed amount net of an allowance for bad debts. NSP-Wisconsin establishes an allowance for uncollectible receivables based on a policy that reflects its expected exposure to the credit risk of customers.
Inventory
Inventory — All inventory is recorded at average cost.
Renewable Energy Credits
RECs — RECs are marketable environmental instruments that represent proof that energy was generated from eligible renewable energy sources. RECs are awarded upon delivery of the associated energy and can be bought and sold. RECs are typically used as a form of measurement of compliance to RPS enacted by those states that are encouraging construction and consumption from renewable energy sources, but can also be sold separately from the energy produced. NSP-Wisconsin acquires RECs from the generation or purchase of renewable power.  

When RECs are purchased or acquired in the course of generation they are recorded as inventory at cost. The cost of RECs that are utilized for compliance purposes is recorded as electric fuel and purchased power expense.

Sales of RECs that are purchased or acquired in the course of generation are recorded in electric utility operating revenues on a gross basis. The cost of these RECs and related transaction costs are recorded in electric fuel and purchased power expense.

Emission Allowances
Emission Allowances — Emission allowances, including the annual SO2 and NOx emission allowance entitlement received from the EPA, are recorded at cost plus associated broker commission fees. NSP-Wisconsin follows the inventory accounting model for all emission allowances. Sales of emission allowances are included in electric utility operating revenues and the operating activities section of the consolidated statements of cash flows.
Environmental Costs
Environmental Costs — Environmental costs are recorded when it is probable NSP-Wisconsin is liable for remediation costs and the liability can be reasonably estimated. Costs are deferred as a regulatory asset if it is probable that the costs will be recovered from customers in future rates. Otherwise, the costs are expensed. If an environmental expense is related to facilities currently in use, such as emission-control equipment, the cost is capitalized and depreciated over the life of the plant.

Estimated remediation costs, excluding inflationary increases, are recorded based on experience, an assessment of the current situation and the technology currently available for use in the remediation.  The recorded costs are regularly adjusted as estimates are revised and remediation proceeds.  If other participating PRPs exist and acknowledge their potential involvement with a site, costs are estimated and recorded only for NSP-Wisconsin’s expected share of the cost.  Any future costs of restoring sites where operation may be extended are treated as a capitalized cost of plant retirement.  The depreciation expense levels recoverable in rates include a provision for removal expenses, which may include final remediation costs.  Removal costs recovered in rates before the related costs are incurred are classified as a regulatory liability.

See Note 11 for further discussion of environmental costs.
Benefit Plans and Other Postretirement Benefits
Benefit Plans and Other Postretirement Benefits — NSP-Wisconsin maintains pension and postretirement benefit plans for eligible employees.  Recognizing the cost of providing benefits and measuring the projected benefit obligation of these plans under applicable accounting guidance requires management to make various assumptions and estimates.

Based on regulatory recovery mechanisms, certain unrecognized actuarial gains and losses and unrecognized prior service costs or credits are recorded as regulatory assets and liabilities, rather than OCI.

See Note 7 for further discussion of benefit plans and other postretirement benefits.
Guarantees
Guarantees — NSP-Wisconsin recognizes, upon issuance or modification of a guarantee, a liability for the fair market value of the obligation that has been assumed in issuing the guarantee.  This liability includes consideration of specific triggering events and other conditions which may modify the ongoing obligation to perform under the guarantee.

The obligation recognized is reduced over the term of the guarantee as NSP-Wisconsin is released from risk under the guarantee.  See Note 11 for specific details of issued guarantees.
Reclassifications
Reclassifications — Due to adoption of new accounting pronouncements, certain previously reported amounts have been reclassified to conform to the current year presentation.
Subsequent Events
Subsequent Events — Management has evaluated the impact of events occurring after Dec. 31, 2016 up to the date of issuance of these consolidated financial statements.  These statements contain all necessary adjustments and disclosures resulting from that evaluation.
v3.6.0.2
Selected Balance Sheet Data (Tables)
 12 Months Ended
Dec. 31, 2016
Balance Sheet Related Disclosures [Abstract]  
Accounts Receivable, Net
(Thousands of Dollars)
 
Dec. 31, 2016
 
Dec. 31, 2015
Accounts receivable, net (a)
 
 
 
 
Accounts receivable
 
$
58,896

 
$
61,506

Less allowance for bad debts
 
(4,865
)
 
(5,128
)
 
 
$
54,031

 
$
56,378
Inventories
(Thousands of Dollars)
 
Dec. 31, 2016
 
Dec. 31, 2015
Inventories
 
 
 
 
Materials and supplies
 
$
6,582

 
$
6,785

Fuel
 
4,743

 
6,528

Natural gas
 
6,984

 
8,246

 
 
$
18,309

 
$
21,559
Property, Plant and Equipment, Net
(Thousands of Dollars)
 
Dec. 31, 2016
 
Dec. 31, 2015
Property, plant and equipment, net
 
 
 
 
Electric plant
 
$
2,499,401

 
$
2,411,562

Natural gas plant
 
294,986

 
275,376

Common and other property
 
156,316

 
132,329

CWIP
 
118,822

 
65,755

Total property, plant and equipment
 
3,069,525

 
2,885,022

Less accumulated depreciation
 
(1,121,888
)
 
(1,056,943
)
 
 
$
1,947,637

 
$
1,828,079
v3.6.0.2
Borrowings and Other Financing Instruments (Tables)
 12 Months Ended
Dec. 31, 2016
Borrowings and Other Financing Instruments [Abstract]  
Credit Facilities
At Dec. 31, 2016, NSP-Wisconsin had the following committed credit facility available (in millions):
Credit Facility (a)
 
Drawn (b)
 
Available
$
150

 
$
60

 
$
90


(a) 
This credit facility matures in June 2021.
(b) 
Includes outstanding commercial paper.

A
Commercial Paper  
Borrowings and Other Financing Instruments [Abstract]  
Short-term Borrowings
Commercial Paper — NSP-Wisconsin meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under its credit facility. Commercial paper outstanding for NSP-Wisconsin was as follows:
(Amounts in Millions, Except Interest Rates)
 
Three Months Ended Dec. 31, 2016
Borrowing limit
 
$
150

Amount outstanding at period end
 
60

Average amount outstanding
 
32

Maximum amount outstanding
 
64

Weighted average interest rate, computed on a daily basis
 
0.73
%
Weighted average interest rate at period end
 
0.95


(Amounts in Millions, Except Interest Rates)
 
Twelve Months Ended Dec. 31, 2016
 
Twelve Months Ended Dec. 31, 2015
 
Twelve Months Ended Dec. 31, 2014
Borrowing limit
 
$
150

 
$
150

 
$
150

Amount outstanding at period end
 
60

 
10

 
78

Average amount outstanding
 
15

 
39

 
46

Maximum amount outstanding
 
64

 
122

 
101

Weighted average interest rate, computed on a daily basis
 
0.69
%
 
0.44
%
 
0.27
%
Weighted average interest rate at period end
 
0.95

 
0.70

 
0.55
Notes Payable, Other Payables  
Borrowings and Other Financing Instruments [Abstract]  
Short-term Borrowings
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, 2016
 
Dec. 31, 2015
Notes payable to affiliates
 
$
0.5

 
$
0.5

Weighted average interest rate
 
0.95
%
 
0.87
%
v3.6.0.2
Joint Ownership of Transmission Facilities (Tables)
 12 Months Ended
Dec. 31, 2016
Joint Ownership of Transmission Facilities [Abstract]  
Investments in Jointly Owned Transmission Facilities
Following are the investments by NSP-Wisconsin in jointly owned transmission facilities and the related ownership percentages as of Dec. 31, 2016:
(Thousands of Dollars)
 
Plant in
Service
 
Accumulated Depreciation
 
CWIP
 
Ownership %
Electric Transmission:
 
 
 
 
 
 
 
 
CapX2020 Transmission
 
$
164,040

 
$
10,874

 
$
42,546

 
81
%
La Crosse, Wis. to Madison, Wis.
 
—

 
—

 
41,131

 
37

Total NSP-Wisconsin
 
$
164,040

 
$
10,874

 
$
83,677

 
 
v3.6.0.2
Income Taxes (Tables)
 12 Months Ended
Dec. 31, 2016
Income Tax Disclosure [Abstract]  
Reconciliation of Unrecognized Tax Benefits

A reconciliation of the amount of unrecognized tax benefit is as follows:
(Millions of Dollars)
 
Dec. 31, 2016
 
Dec. 31, 2015
Unrecognized tax benefit — Permanent tax positions
 
$
0.4

 
$
0.2

Unrecognized tax benefit — Temporary tax positions
 
4.9

 
4.3

Total unrecognized tax benefit
 
$
5.3

 
$
4.5


A reconciliation of the beginning and ending amount of unrecognized tax benefit is as follows:
(Millions of Dollars)
 
2016
 
2015
 
2014
Balance at Jan. 1
 
$
4.5

 
$
3.0

 
$
1.5

Additions based on tax positions related to the current year
 
0.5

 
1.9

 
1.9

Reductions based on tax positions related to the current year
 
—

 
(0.3
)
 
(0.2
)
Additions for tax positions of prior years
 
0.5

 
0.8

 
0.1

Reductions for tax positions of prior years
 
(0.2
)
 
(0.9
)
 
(0.2
)
Settlements with taxing authorities
 
—

 
—

 
(0.1
)
Balance at Dec. 31
 
$
5.3

 
$
4.5

 
$
3.0
Tax Benefits Associated with NOL and Tax Credit Carryforwards
The unrecognized tax benefit amounts were reduced by the tax benefits associated with NOL and tax credit carryforwards.  The amounts of tax benefits associated with NOL and tax credit carryforwards are as follows:
(Millions of Dollars)
 
Dec. 31, 2016
 
Dec. 31, 2015
NOL and tax credit carryforwards
 
$
(1.2
)
 
$
(0.9
)
NOL and Tax Credit Carryforwards
Other Income Tax Matters — NOL amounts represent the amount of the tax loss that is carried forward and tax credits represent the deferred tax asset. NOL and tax credit carryforwards as of Dec. 31 were as follows:
(Millions of Dollars)
 
2016
 
2015
Federal NOL carryforward
 
$
97

 
$
103

Federal tax credit carryforwards
 
4

 
5

State NOL carryforward
 
3

 
3
Schedule of Effective Income Tax Rate Reconciliation
2031.

Total income tax expense from operations differs from the amount computed by applying the statutory federal income tax rate to income before income tax expense. The following reconciles such differences for the years ending Dec. 31:
 
 
2016
 
2015
 
2014
Federal statutory rate
 
35.0
 %
 
35.0
 %
 
35.0
 %
Increases (decreases) in tax from:
 
 
 
 
 
 
State income taxes, net of federal income tax benefit
 
4.9

 
4.8

 
4.9

Change in unrecognized tax benefits
 
0.1

 
0.1

 
—

Tax credits recognized
 
(0.7
)
 
(0.7
)
 
(0.7
)
Regulatory differences — utility plant items
 
(0.7
)
 
(1.7
)
 
(1.6
)
Other, net
 
(0.3
)
 
(0.3
)
 
(0.1
)
Effective income tax rate
 
38.3
 %
 
37.2
 %
 
37.5
 %
Schedule of Components of Income Tax Expense (Benefit)
The components of income tax expense for the years ending Dec. 31 were:
(Thousands of Dollars)
 
2016
 
2015
 
2014
Current federal tax expense (benefit)
 
$
5,367

 
$
(4,715
)
 
$
(3,932
)
Current state tax expense
 
131

 
2,150

 
453

Current change in unrecognized tax expense
 
559

 
1,498

 
1,013

Deferred federal tax expense
 
29,588

 
40,580

 
38,321

Deferred state tax expense
 
8,212

 
6,675

 
8,042

Deferred change in unrecognized tax benefit
 
(432
)
 
(1,422
)
 
(967
)
Deferred investment tax credits
 
(523
)
 
(528
)
 
(527
)
Total income tax expense
 
$
42,902

 
$
44,238

 
$
42,403


The components of deferred income tax expense for the years ending Dec. 31 were:
(Thousands of Dollars)
 
2016
 
2015
 
2014
Deferred tax expense excluding items below
 
$
39,530

 
$
51,084

 
$
49,793

Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities
 
(2,112
)
 
(5,200
)
 
(4,346
)
Tax expense allocated to other comprehensive income and other
 
(50
)
 
(51
)
 
(51
)
Deferred tax expense
 
$
37,368

 
$
45,833

 
$
45,396
Schedule of Deferred Tax Assets and Liabilities

The components of the net deferred tax liability at Dec. 31 were as follows:
(Thousands of Dollars)
 
2016
 
2015
Deferred tax liabilities:
 
 
 
 
Difference between book and tax bases of property
 
$
412,071

 
$
382,592

Regulatory assets
 
75,392

 
78,233

Employee benefits
 
15,443

 
18,028

Other
 
9,949

 
10,190

Total deferred tax liabilities
 
$
512,855

 
$
489,043

Deferred tax assets:
 
 
 
 
NOL carryforward
 
$
35,216

 
$
37,508

Environmental remediation
 
25,842

 
37,938

Regulatory liabilities
 
5,779

 
9,328

Deferred investment tax credits
 
4,996

 
5,312

Tax credit carryforward
 
3,704

 
4,760

Other
 
6,725

 
3,134

Total deferred tax assets
 
$
82,262

 
$
97,980

Net deferred tax liability
 
$
430,593

 
$
391,063
v3.6.0.2
Benefit Plans and Other Postretirement Benefits (Tables)
 12 Months Ended
Dec. 31, 2016
Benefit Plans and Other Postretirement Benefits [Abstract]  
Projected Benefit Payments for the Pension and Postretirement Benefit Plans
The following table lists NSP-Wisconsin’s projected benefit payments for the pension and postretirement benefit plans:
(Thousands of Dollars)
 
Projected Pension
Benefit Payments
 
Gross Projected
Postretirement
Health Care
Benefit Payments
 
Expected Medicare
Part D Subsidies
 
Net Projected
Postretirement
Health Care
Benefit Payments
2017
 
$
12,324

 
$
1,371

 
$
6

 
$
1,365

2018
 
11,496

 
1,308

 
5

 
1,303

2019
 
12,957

 
1,271

 
4

 
1,267

2020
 
13,329

 
1,226

 
4

 
1,222

2021
 
12,964

 
1,169

 
3

 
1,166

2022-2026
 
61,280

 
5,031

 
15

 
5,016
Contributions to Multiemployer Plans
Contributions to multiemployer plans were as follows for the years ended Dec. 31, 2016, 2015 and 2014. There were no significant changes to the nature or magnitude of the participation of NSP-Wisconsin in multiemployer plans for the years presented:
(Thousands of Dollars)
 
2016
 
2015
 
2014
Multiemployer plan contributions:
 
 
 
 
 
 
Pension
 
$
707

 
$
944

 
$
156
Pension Plans  
Benefit Plans and Other Postretirement Benefits [Abstract]  
Target Asset Allocations and Plan Assets Measured at Fair Value
The following tables present, for each of the fair value hierarchy levels, NSP-Wisconsin’s pension plan assets that are measured at fair value as of Dec. 31, 2016 and 2015:
 
 
Dec. 31, 2016
(Thousands of Dollars)
 
Level 1
 
Level 2
 
Level 3
 
Investments Measured at NAV (a)
 
Total
Cash equivalents
 
$
3,939

 
$
—

 
$
—

 
$
—

 
$
3,939

Commingled funds:
 
 
 
 
 
 
 
 
 
 
U.S. equity funds
 
—

 
—

 
—

 
21,415

 
21,415

Non U.S. equity funds
 
—

 
—

 
—

 
16,348

 
16,348

U.S. corporate bond funds
 
—

 
—

 
—

 
10,581

 
10,581

Emerging market equity funds
 
—

 
—

 
—

 
8,577

 
8,577

Emerging market debt funds
 
—

 
—

 
—

 
7,306

 
7,306

Commodity funds
 
—

 
—

 
—

 
889

 
889

Private equity investments
 
—

 
—

 
—

 
4,652

 
4,652

Real estate
 
—

 
—

 
—

 
8,108

 
8,108

Other commingled funds
 
—

 
—

 
—

 
8,752

 
8,752

Debt securities:
 
 
 
 
 
 
 
 
 
 
Government securities
 
—

 
12,773

 
—

 
—

 
12,773

U.S. corporate bonds
 
—

 
9,432

 
—

 
—

 
9,432

Non U.S. corporate bonds
 
—

 
1,514

 
—

 
—

 
1,514

Mortgage-backed securities
 
—

 
254

 
—

 
—

 
254

Asset-backed securities
 
—

 
120

 
—

 
—

 
120

Equity securities:
 
 
 
 
 
 
 
 
 
 
U.S. equities
 
4,219

 
—

 
—

 
—

 
4,219

Other
 
—

 
97

 
—

 
—

 
97

Total
 
$
8,158

 
$
24,190

 
$
—

 
$
86,628

 
$
118,976


(a) 
Based on the requirements of ASU No. 2015-07, investments measured at fair value using a NAV methodology have not been classified in the fair value hierarchy. See Note 2 for further information on the adoption of ASU No. 2015-07.

 
 
Dec. 31, 2015
(Thousands of Dollars)
 
Level 1
 
Level 2
 
Level 3
 
Investments Measured at NAV (a)
 
Total
Cash equivalents
 
$
6,005

 
$
—

 
$
—

 
$
—

 
$
6,005

Derivatives
 
—

 
89

 
—

 
—

 
89

Commingled funds:
 
 
 
 
 
 
 
 
 
 
U.S. equity funds
 
—

 
—

 
—

 
17,338

 
17,338

Non U.S. equity funds
 
—

 
—

 
—

 
16,710

 
16,710

U.S. corporate bond funds
 
—

 
—

 
—

 
10,001

 
10,001

Emerging market equity funds
 
—

 
—

 
—

 
7,491

 
7,491

Emerging market debt funds
 
—

 
—

 
—

 
7,245

 
7,245

Commodity funds
 
—

 
—

 
—

 
2,461

 
2,461

Private equity investments
 
—

 
—

 
—

 
5,967

 
5,967

Real estate
 
—

 
—

 
—

 
8,663

 
8,663

Other commingled funds
 
—

 
—

 
—

 
9,321

 
9,321

Debt securities:
 
 
 
 
 
 
 
 
 
 
Government securities
 
—

 
13,048

 
—

 
—

 
13,048

U.S. corporate bonds
 
—

 
9,008

 
—

 
—

 
9,008

Non U.S. corporate bonds
 
—

 
1,446

 
—

 
—

 
1,446

Asset-backed securities
 
—

 
101

 
—

 
—

 
101

Equity securities:
 
 
 
 
 
 
 
 
 
 
U.S. equities
 
4,213

 
—

 
—

 
—

 
4,213

Other
 
—

 
207

 
—

 
—

 
207

Total
 
$
10,218

 
$
23,899

 
$
—

 
$
85,197

 
$
119,314



(a) 
Based on the requirements of ASU No. 2015-07, investments measured at fair value using a NAV methodology have not been classified in the fair value hierarchy. See Note 2 for further information on the adoption of ASU No. 2015-07.
The following table presents the target pension asset allocations for NSP-Wisconsin at Dec. 31 for the upcoming year:
 
 
2016
 
2015
Domestic and international equity securities
 
40
%
 
41
%
Long-duration fixed income and interest rate swap securities
 
23

 
23

Short-to-intermediate fixed income securities
 
16

 
14

Alternative investments
 
19

 
20

Cash
 
2

 
2

Total
 
100
%
 
100
%
Change in Projected Benefit Obligation
A comparison of the actuarially computed pension benefit obligation and plan assets for NSP-Wisconsin is presented in the following table:
(Thousands of Dollars)
 
2016
 
2015
Accumulated Benefit Obligation at Dec. 31
 
$
146,448

 
$
140,917

 
 
 
 
 
Change in Projected Benefit Obligation:
 
 
 
 
Obligation at Jan. 1
 
$
152,545

 
$
165,669

Service cost
 
4,417

 
4,759

Interest cost
 
6,816

 
6,520

Plan amendments
 
305

 
—

Actuarial loss (gain)
 
7,315

 
(11,159
)
Benefit payments
 
(13,941
)
 
(13,244
)
Obligation at Dec. 31
 
$
157,457

 
$
152,545
Change in Fair Value of Plan Assets
(Thousands of Dollars)
 
2016
 
2015
Change in Fair Value of Plan Assets:
 
 
 
 
Fair value of plan assets at Jan. 1
 
$
119,314

 
$
132,713

Actual return (loss) on plan assets
 
6,163

 
(5,087
)
Employer contributions
 
7,440

 
4,932

Benefit payments
 
(13,941
)
 
(13,244
)
Fair value of plan assets at Dec. 31
 
$
118,976

 
$
119,314
Funded Status of Plans
(Thousands of Dollars)
 
2016
 
2015
Funded Status of Plans at Dec. 31:
 
 
 
 
Funded status (a)
 
$
(38,481
)
 
$
(33,231
)
(a) 
Amounts are recognized in noncurrent liabilities on NSP-Wisconsin’s consolidated balance sheets.
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost
(Thousands of Dollars)
 
2016
 
2015
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:
 
 
 
 
Net loss
 
$
91,531

 
$
86,614

Prior service cost
 
750

 
556

Total
 
$
92,281

 
$
87,170
Amounts Not Yet Recognized as Components of Net Periodic Benefit Costs Recorded on the Balance Sheet Based Upon Expected Recovery in Rates
(Thousands of Dollars)
 
2016
 
2015
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
 
$
5,972

 
$
6,300

Noncurrent regulatory assets
 
86,309

 
80,870

Total
 
$
92,281

 
$
87,170
Schedule of Assumptions Used
 
 
2016
 
2015
 
2014
Significant Assumptions Used to Measure Costs:
 
 
 
 
 
 
Discount rate
 
4.66
%
 
4.11
%
 
4.75
%
Expected average long-term increase in compensation level
 
4.00

 
3.75

 
3.75

Expected average long-term rate of return on assets
 
7.10

 
7.25

 
7.25

Measurement date
 
Dec. 31, 2016
 
Dec. 31, 2015
 
 
2016
 
2015
Significant Assumptions Used to Measure Benefit Obligations:
 
 
 
 
Discount rate for year-end valuation
 
4.13
%
 
4.66
%
Expected average long-term increase in compensation level
 
3.75

 
4.00

Mortality table
 
RP 2014

 
RP 2014
Components of Net Periodic Benefit Costs
The components of NSP-Wisconsin’s net periodic pension cost were:
(Thousands of Dollars)
 
2016
 
2015
 
2014
Service cost
 
$
4,417

 
$
4,759

 
$
4,527

Interest cost
 
6,816

 
6,520

 
7,257

Expected return on plan assets
 
(9,157
)
 
(9,483
)
 
(9,642
)
Amortization of prior service cost
 
111

 
111

 
111

Amortization of net loss
 
5,392

 
6,804

 
6,617

Net periodic pension cost
 
$
7,579

 
$
8,711

 
$
8,870
Postretirement Benefit Plan  
Benefit Plans and Other Postretirement Benefits [Abstract]  
Target Asset Allocations and Plan Assets Measured at Fair Value
The following table presents the target postretirement asset allocations for Xcel Energy Inc. and NSP-Wisconsin at Dec. 31 for the upcoming year:
 
 
2016
 
2015
Domestic and international equity securities
 
25
%
 
25
%
Short-to-intermediate fixed income securities
 
57

 
57

Alternative investments
 
13

 
13

Cash
 
5

 
5

Total
 
100
%
 
100
%
The following tables present, for each of the fair value hierarchy levels, NSP-Wisconsin’s proportionate allocation of the total postretirement benefit plan assets that are measured at fair value as of Dec. 31, 2016 and 2015:
 
 
Dec. 31, 2016
(Thousands of Dollars)
 
Level 1
 
Level 2
 
Level 3
 
Investments Measured at NAV (a)

 
Total
Cash equivalents
 
$
25

 
$
—

 
$
—

 
$
—

 
$
25

Insurance contracts
 
—

 
58

 
—

 
—

 
58

Commingled funds:
 
 
 
 
 
 
 
 
 
 
U.S. equity funds
 
—

 
—

 
—

 
67

 
67

U.S fixed income funds
 
—

 
—

 
—

 
33

 
33

Emerging market debt funds
 
—

 
—

 
—

 
38

 
38

Other commingled funds
 
—

 
—

 
—

 
67

 
67

Debt securities:
 
 
 
 
 
 
 
 
 
 
Government securities
 
—

 
46

 
—

 
—

 
46

U.S. corporate bonds
 
—

 
77

 
—

 
—

 
77

Non U.S. corporate bonds
 
—

 
21

 
—

 
—

 
21

Asset-backed securities
 
—

 
23

 
—

 
—

 
23

Mortgage-backed securities
 
—

 
36

 
—

 
—

 
36

Equity securities:
 
 
 
 
 
 
 
 
 
 
Non U.S. equities
 
50

 
—

 
—

 
—

 
50

Other
 
—

 
2

 
—

 
—

 
2

Total
 
$
75

 
$
263

 
$
—

 
$
205

 
$
543

(a) 
Based on the requirements of ASU No. 2015-07, investments measured at fair value using a NAV methodology have not been classified in the fair value hierarchy. See Note 2 for further information on the adoption of ASU No. 2015-07.

 
 
Dec. 31, 2015
(Thousands of Dollars)
 
Level 1
 
Level 2
 
Level 3
 
Investments Measured at NAV (a)

 
Total
Cash equivalents
 
$
18

 
$
—

 
$
—

 
$
—

 
$
18

Insurance contracts
 
—

 
44

 
—

 
—

 
44

Commingled funds:
 
 
 
 
 
 
 
 
 
 
U.S. equity funds
 
—

 
—

 
—

 
36

 
36

Non U.S. equity funds
 
—

 
—

 
—

 
31

 
31

U.S fixed income funds
 
—

 
—

 
—

 
23

 
23

Emerging market equity funds
 
—

 
—

 
—

 
10

 
10

Emerging market debt funds
 
—

 
—

 
—

 
33

 
33

Other commingled funds
 
—

 
—

 
—

 
58

 
58

Debt securities:
 
 
 
 
 
 
 
 
 
 
Government securities
 
—

 
37

 
—

 
—

 
37

U.S. corporate bonds
 
—

 
56

 
—

 
—

 
56

Non U.S. corporate bonds
 
—

 
12

 
—

 
—

 
12

Asset-backed securities
 
—

 
27

 
—

 
—

 
27

Mortgage-backed securities
 
—

 
33

 
—

 
—

 
33

Total
 
$
18

 
$
209

 
$
—

 
$
191

 
$
418


(a) 
Based on the requirements of ASU No. 2015-07, investments measured at fair value using a NAV methodology have not been classified in the fair value hierarchy. See Note 2 for further information on the adoption of ASU No. 2015-07.
Change in Projected Benefit Obligation
A comparison of the actuarially computed benefit obligation and plan assets for NSP-Wisconsin is presented in the following table:
(Thousands of Dollars)
 
2016
 
2015
Change in Projected Benefit Obligation:
 
 
 
 
Obligation at Jan. 1
 
$
14,718

 
$
16,768

Service cost
 
24

 
29

Interest cost
 
651

 
653

Medicare subsidy reimbursements
 
7

 
13

Plan participants’ contributions
 
87

 
130

Actuarial loss (gain)
 
775

 
(1,645
)
Benefit payments
 
(1,289
)
 
(1,230
)
Obligation at Dec. 31
 
$
14,973

 
$
14,718
Change in Fair Value of Plan Assets
(Thousands of Dollars)
 
2016
 
2015
Change in Fair Value of Plan Assets:
 
 
 
 
Fair value of plan assets at Jan. 1
 
$
418

 
$
512

Actual loss on plan assets
 
(12
)
 
(12
)
Plan participants’ contributions
 
87

 
130

Employer contributions
 
1,339

 
1,018

Benefit payments
 
(1,289
)
 
(1,230
)
Fair value of plan assets at Dec. 31
 
$
543

 
$
418
Funded Status of Plans
(Thousands of Dollars)
 
2016
 
2015
Funded Status of Plans at Dec. 31:
 
 
 
 
Funded status
 
$
(14,430
)
 
$
(14,300
)
Current liabilities
 
(822
)
 
(1,017
)
Noncurrent liabilities
 
(13,608
)
 
(13,283
)
Net postretirement amounts recognized on consolidated balance sheets
 
$
(14,430
)
 
$
(14,300
)
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost
(Thousands of Dollars)
 
2016
 
2015
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:
 
 
 
 
Net loss
 
$
8,883

 
$
8,402

Prior service credit
 
(2,134
)
 
(2,485
)
Total
 
$
6,749

 
$
5,917
Amounts Not Yet Recognized as Components of Net Periodic Benefit Costs Recorded on the Balance Sheet Based Upon Expected Recovery in Rates
(Thousands of Dollars)
 
2016
 
2015
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
 
$
—

 
$
99

Noncurrent regulatory assets
 
6,749

 
5,818

Total
 
$
6,749

 
$
5,917
Schedule of Assumptions Used
 
 
2016
 
2015
 
2014
Significant Assumptions Used to Measure Costs:
 
 
 
 
 
 
Discount rate
 
4.65
%
 
4.08
%
 
4.82
%
Expected average long-term rate of return on assets
 
5.80

 
5.80

 
7.08

Measurement date
 
Dec. 31, 2016
 
Dec. 31, 2015
 
 
2016
 
2015
Significant Assumptions Used to Measure Benefit Obligations:
 
 
 
 
Discount rate for year-end valuation
 
4.13
%
 
4.65
%
Mortality table
 
RP 2014

 
RP 2014

Health care costs trend rate — initial
 
5.50
%
 
6.00
%
Effects of One-Percent Change in Assumed Health Care Cost Trend Rate
A one-percent change in the assumed health care cost trend rate would have the following effects on NSP-Wisconsin:
 
 
One-Percentage Point
(Thousands of Dollars)
 
Increase
 
Decrease
APBO
 
$
1,423

 
$
(1,212
)
Service and interest components
 
71

 
(60
)
Components of Net Periodic Benefit Costs
The components of NSP-Wisconsin’s net periodic postretirement benefit costs were:
(Thousands of Dollars)
 
2016
 
2015
 
2014
Service cost
 
$
24

 
$
29

 
$
35

Interest cost
 
651

 
653

 
791

Expected return on plan assets
 
(24
)
 
(30
)
 
(52
)
Amortization of prior service credit
 
(351
)
 
(351
)
 
(351
)
Amortization of net loss
 
330

 
456

 
666

Net periodic postretirement benefit cost
 
$
630

 
$
757

 
$
1,089
v3.6.0.2
Other Income, Net (Tables)
 12 Months Ended
Dec. 31, 2016
Other Income and Expenses [Abstract]  
Other Income, Net
Other income, net for the years ended Dec. 31 consisted of the following:
(Thousands of Dollars)
 
2016
 
2015
 
2014
Interest income
 
$
244

 
$
332

 
$
368

Other nonoperating income
 
208

 
789

 
321

Insurance policy expense
 
22

 
(228
)
 
(409
)
Other nonoperating expense
 
(13
)
 
(10
)
 
(10
)
Other income, net
 
$
461

 
$
883

 
$
270
v3.6.0.2
Fair Value of Financial Assets and Liabilities (Tables)
 12 Months Ended
Dec. 31, 2016
Fair Value Disclosures [Abstract]  
Gross Notional Amounts of Commodity Forwards and Options
The following table details the gross notional amounts of commodity options at Dec. 31:
(Amounts in Thousands) (a)(b)
 
2016
 
2015
MMBtu of natural gas
 
255

 
388


(a) 
Amounts are not reflective of net positions in the underlying commodities.
(b) 
Notional amounts for options are included on a gross basis, but are weighted for the probability of exercise.
Financial Impact of Qualifying Cash Flow Hedges on Accumulated Other Comprehensive Loss
Financial Impact of Qualifying Cash Flow Hedges — The impact of qualifying interest rate cash flow hedges on NSP-Wisconsin’s accumulated other comprehensive loss, included in the consolidated statements of common stockholder’s equity and in the consolidated statements of comprehensive income, is detailed in the following table:
(Thousands of Dollars)
 
2016
 
2015
 
2014
Accumulated other comprehensive loss related to cash flow hedges at Jan. 1
 
$
(209
)
 
$
(285
)
 
$
(361
)
After-tax net realized losses on derivative transactions reclassified into earnings
 
76

 
76

 
76

Accumulated other comprehensive loss related to cash flow hedges at Dec. 31
 
$
(133
)
 
$
(209
)
 
$
(285
)
Derivative Assets and Liabilities Measured at Fair Value on a Recurring Basis by Hierarchy Level
Recurring Fair Value Measurements — The following table presents for each of the fair value hierarchy levels, NSP-Wisconsin’s derivative assets and liabilities measured at fair value on a recurring basis:
 
 
Dec. 31, 2016
 
 
Fair Value
 
Fair Value
Total
 
Counterparty
Netting (a)
 
 
(Thousands of Dollars)
 
Level 1
 
Level 2
 
Level 3
 
 
 
Total (b)
Current derivative assets
 
 
 
 
 
 
 
 
 
 
 
 
Natural gas commodity
 
$
—

 
$
149

 
$
—

 
$
149

 
$
—

 
$
149

 
 
Dec. 31, 2015
 
 
Fair Value
 
Fair Value
Total
 
Counterparty
Netting (a)
 
 
(Thousands of Dollars)
 
Level 1
 
Level 2
 
Level 3
 
 
 
Total (c)
Current derivative assets
 
 
 
 
 
 
 
 
 
 
 
 
Natural gas commodity
 
$
—

 
$
15

 
$
—

 
$
15

 
$
(11
)
 
$
4

Total current derivative assets
 
$
—

 
$
15

 
$
—

 
$
15

 
$
(11
)
 
$
4

Current derivative liabilities
 
 
 
 
 
 
 
 
 
 
 
 
Natural gas commodity
 
$
—

 
$
194

 
$
—

 
$
194

 
$
(11
)
 
$
183

Total current derivative liabilities
 
$
—

 
$
194

 
$
—

 
$
194

 
$
(11
)
 
$
183


(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, 2016 and 2015.  The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.
(b) 
Included in prepayments and other current assets balance of $3.8 million at Dec. 31, 2016 in the consolidated balance sheets.
(c) 
Included in prepayments and other current assets balance of $2.4 million and other current liabilities balance of $15.1 million at Dec. 31, 2015 in the consolidated balance sheets.
Carrying Amount and Fair Value of Long-term Debt
As of Dec. 31, 2016 and 2015, other financial instruments for which the carrying amount did not equal fair value were as follows:
 
 
2016
 
2015
(Thousands of Dollars)
 
Carrying Amount
 
Fair Value
 
Carrying Amount
 
Fair Value
Long-term debt, including current portion (a)
 
$
663,069

 
$
730,284

 
$
662,449

 
$
742,565


(a) 
Amounts reflect the classification of debt issuance costs as a deduction from the carrying amount of the related debt. See Note 2, Accounting Pronouncements for more information on the adoption of ASU No. 2015-03.
v3.6.0.2
Rate Matters Rate Matters (Tables)
 12 Months Ended
Dec. 31, 2016
Public Utilities, General Disclosures [Abstract]  
NSP-WI 2017 Electric Rate Request [Table Text Block]
The differences between NSP-Wisconsin’s original electric rate request and the PSCW’s approved electric increase are summarized below:
Electric Rate Request (Millions of Dollars)
 
NSP-Wisconsin Request
 
Final Decision
Rate base investments
 
$
11.0

 
$
7.6

Generation and transmission expenses (excluding fuel and purchased power) (a)
 
6.8

 
6.1

Fuel and purchased power expenses
 
11.0

 
10.7

Subtotal
 
28.8

 
24.4

2015 fuel refund (b)
 
(9.5
)
 
—

Department of Energy settlement refund
 
(1.9
)
 
(1.9
)
Total electric rate increase
 
$
17.4

 
$
22.5


(a) 
Includes Interchange Agreement billings. For financial reporting purposes, these expenses are included in O&M.
(b) 
In July 2016, the PSCW required NSP-Wisconsin to return the 2015 fuel refund directly to customers, rather than using it to offset the proposed 2017 rate increase, as originally proposed by NSP-Wisconsin. This decision, when combined with the increase in forecasted fuel and purchased power expense, effectively increased NSP-Wisconsin’s requested electric rate increase to $29.9 million, or 4.2 percent.
v3.6.0.2
Commitments and Contingencies (Tables)
 12 Months Ended
Dec. 31, 2016
Commitments and Contingencies Disclosure [Abstract]  
Estimated Minimum Purchases Under Fuel Contracts
The estimated minimum purchases for NSP-Wisconsin under these contracts as of Dec. 31, 2016 are as follows:
(Millions of Dollars)
 
Coal
 
Natural gas
supply
 
Natural gas
storage and
transportation
2017
 
$
6.9

 
$
10.9

 
$
13.2

2018
 
2.5

 
0.3

 
12.3

2019
 
0.8

 
0.3

 
11.4

2020
 
0.8

 
0.3

 
9.1

2021
 
0.8

 
0.3

 
8.4

Thereafter
 
1.7

 
0.4

 
36.1

Total (a)
 
$
13.5

 
$
12.5

 
$
90.5


(a) 
Excludes additional amounts allocated to NSP-Wisconsin through intercompany charges.
Future Commitments Under Operating Leases
Future commitments under operating leases are:
(Millions of Dollars)
 
 
2017
 
$
1.0

2018
 
1.0

2019
 
1.0

2020
 
0.9

2021
 
0.8

Thereafter
 
5.3

Total
 
$
10.0
Low-income Housing Limited Partnerships
Amounts reflected in NSP-Wisconsin’s consolidated balance sheets for low-income housing limited partnerships include the following:
(Thousands of Dollars)
 
Dec. 31, 2016
 
Dec. 31, 2015
Current assets
 
$
375

 
$
377

Property, plant and equipment, net
 
2,025

 
2,199

Other noncurrent assets
 
125

 
127

Total assets
 
$
2,525

 
$
2,703

 
 
 
 
 
Current liabilities
 
$
1,269

 
$
1,246

Mortgages and other long-term debt payable
 
486

 
537

Other noncurrent liabilities
 
54

 
51

Total liabilities
 
$
1,809

 
$
1,834
Guarantee Issued and Outstanding
The following table presents the guarantee issued and outstanding for NSP-Wisconsin:
(Millions of Dollars)
 
Guarantee
Amount
 
Current
Exposure
 
Term or
Expiration Date
 
Triggering
Event
Guarantee of customer loans for the Farm Rewiring Program(a)
 
$
1.0

 
$
0.1

 
2020
 
(b) 
(a) 
The term of this guarantee expires in 2020, which is the final scheduled repayment date for the loans. As of Dec. 31, 2016, no claims had been made by the lender.
(b) 
The debtor becomes the subject of bankruptcy or other insolvency proceedings.
Asset Retirement Obligations
A reconciliation of NSP-Wisconsin’s AROs for the years ended Dec. 31, 2016 and 2015 is as follows:
(Thousands of Dollars)
 
Beginning Balance
Jan. 1, 2016
 
Liabilities Settled
 
Accretion
 
Cash Flow Revisions
 
Ending Balance
   Dec. 31, 2016 (a)
Electric plant
 
 
 
 
 
 
 
 
 
 
Steam production asbestos
 
$
2,145

 
$
—

 
$
49

 
$
—

 
$
2,194

Steam production ash containment
 
617

 
—

 
18

 
(183
)
 
452

Electric distribution
 
72

 
—

 
3

 
(43
)
 
32

Other
 
391

 
(29
)
 
14

 
—

 
376

Natural gas plant
 
 
 
 
 
 
 
 
 
 
Gas distribution
 
6,367

 
—

 
256

 
1,670

 
8,293

Common and other property
 
 
 
 
 
 
 
 
 
 
Common miscellaneous
 
95

 
—

 
2

 
(52
)
 
45

Total liability (b)
 
$
9,687

 
$
(29
)
 
$
342

 
$
1,392

 
$
11,392


(a) 
There were no ARO liabilities recognized during the year ended Dec. 31, 2016.
(b) 
Included in other long-term liabilities balance in the consolidated balance sheet.

(Thousands of Dollars)
 
Beginning Balance
Jan. 1, 2015
 
Accretion
 
Cash Flow
   Revisions
 
Ending Balance
    Dec. 31, 2015 (a)
Electric plant
 
 
 
 
 
 
 
 
Steam production asbestos
 
$
2,049

 
$
45

 
$
51

 
$
2,145

Steam production ash containment
 
374

 
14

 
229

 
617

Electric distribution
 
37

 
1

 
34

 
72

Other
 
412

 
15

 
(36
)
 
391

Natural gas plant
 
 
 
 
 
 
 
 
Gas distribution
 
6,127

 
240

 
—

 
6,367

Common and other property
 
 
 
 
 
 
 
 
Common miscellaneous
 
91

 
4

 
—

 
95

Total liability (b)
 
$
9,090

 
$
319

 
$
278

 
$
9,687

 
(a) 
There were no ARO liabilities recognized or settled during the year ended Dec. 31, 2015.
(b) 
Included in other long-term liabilities balance in the consolidated balance sheet.
v3.6.0.2
Regulatory Assets and Liabilities (Tables)
 12 Months Ended
Dec. 31, 2016
Regulatory Assets and Liabilities Disclosure [Abstract]  
Regulatory Assets
The components of regulatory assets shown on the consolidated balance sheets of NSP-Wisconsin at Dec. 31, 2016 and 2015 are:
(Thousands of Dollars)
 
See Note(s)
 
Remaining
Amortization Period
 
Dec. 31, 2016
 
Dec. 31, 2015
Regulatory Assets
 
 
 
 
 
Current
 
Noncurrent
 
Current
 
Noncurrent
Environmental remediation costs
 
1, 11
 
Various
 
$
10,669

 
$
148,880

 
$
6,702

 
$
160,699

Pension and retiree medical obligations (a)
 
7
 
Various
 
5,989

 
93,160

 
6,415

 
86,778

Recoverable deferred taxes on AFUDC recorded in plant
 
1
 
Plant lives
 
—

 
22,345

 
—

 
20,586

State commission adjustments
 
1
 
Plant lives
 
703

 
14,008

 
724

 
12,945

Losses on reacquired debt
 
4
 
Term of related debt
 
801

 
3,333

 
803

 
4,134

Deferred income tax adjustment
 
1, 6
 
Typically plant lives
 
—

 
2,078

 
—

 
2,250

Other
 
 
 
Various
 
—

 
2,384

 
1,502

 
1,804

Total regulatory assets
 
 
 
 
 
$
18,162

 
$
286,188

 
$
16,146

 
$
289,196


(a) 
Includes the non-qualified pension plan.
Regulatory Liabilities
The components of regulatory liabilities shown on the consolidated balance sheets of NSP-Wisconsin at Dec. 31, 2016 and 2015 are:
(Thousands of Dollars)
 
See Note(s)
 
Remaining
Amortization Period
 
Dec. 31, 2016
 
Dec. 31, 2015
Regulatory Liabilities
 
 
 
 
 
Current
 
Noncurrent
 
Current
 
Noncurrent
Plant removal costs
 
11
 
Plant lives
 
$
—

 
$
139,735

 
$
—

 
$
132,311

Investment tax credit deferrals
 
1, 6
 
Various
 
—

 
8,342

 
—

 
8,869

Deferred electric production and natural gas costs
 
1
 
Less than one year
 
11,377

 
—

 
9,386

 
—

DOE settlement
 
11
 
Less than one year
 
4,822

 
—

 
1,996

 
—

Conservation programs
 
1
 
Less than one year
 
1,122

 
—

 
339

 
—

Other
 
 
 
Various
 
107

 
112

 
60

 
109

Total regulatory liabilities
 
 
 
 
 
$
17,428

 
$
148,189

 
$
11,781

 
$
141,289
v3.6.0.2
Other Comprehensive Income (Tables)
 12 Months Ended
Dec. 31, 2016
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, 2016 and 2015 were as follows:
 
 
Gains and Losses on Cash Flow Hedges
(Thousands of Dollars)
 
Year Ended Dec. 31, 2016
 
Year Ended Dec. 31, 2015
Accumulated other comprehensive loss at Jan. 1
 
$
(209
)
 
$
(285
)
Losses reclassified from net accumulated other comprehensive loss
 
76

 
76

Net current period other comprehensive income
 
76

 
76

Accumulated other comprehensive loss at Dec. 31
 
$
(133
)
 
$
(209
)
Reclassifications out of Accumulated Other Comprehensive Loss
Reclassifications from accumulated other comprehensive loss for the years ended Dec. 31, 2016 and 2015 were as follows:
 
 
Amounts Reclassified from Accumulated
Other Comprehensive Loss
 
(Thousands of Dollars)
 
Year Ended Dec. 31, 2016
 
Year Ended Dec. 31, 2015
 
Losses on cash flow hedges:
 
 
 
 
 
Interest rate derivatives
 
$
127

(a) 
$
127

(a) 
Total, pre-tax
 
127

 
127

 
Tax benefit
 
(51
)
 
(51
)
 
Total amounts reclassified, net of tax
 
$
76

 
$
76

 

(a) 
Included in interest charges.
v3.6.0.2
Segments and Related Information (Tables)
 12 Months Ended
Dec. 31, 2016
Segment Reporting [Abstract]  
Results from Operations by Reportable Segment
(Thousands of Dollars)
 
Regulated
Electric
 
Regulated
Natural Gas
 
All Other
 
Reconciling
Eliminations
 
Consolidated
Total
2016
 
 
 
 
 
 
 
 
 
 
Operating revenues (a)
 
$
849,946

 
$
106,157

 
$
1,130

 
$
—

 
$
957,233

Intersegment revenues
 
397

 
487

 
—

 
(884
)
 
—

Total revenues
 
$
850,343

 
$
106,644

 
$
1,130

 
$
(884
)
 
$
957,233

 
 
 
 
 
 
 
 
 
 
 
Depreciation and amortization
 
$
81,299

 
$
16,794

 
$
201

 
$
—

 
$
98,294

Interest charges and financing costs
 
29,749

 
2,855

 
25

 
—

 
32,629

Income tax expense (benefit)
 
40,547

 
2,445

 
(90
)
 
—

 
42,902

Net income (loss)
 
65,002

 
4,503

 
(370
)
 
—

 
69,135

(Thousands of Dollars)
 
Regulated
Electric
 
Regulated
Natural Gas
 
All Other
 
Reconciling
Eliminations
 
Consolidated
Total
2015
 
 
 
 
 
 
 
 
 
 
Operating revenues (a)
 
$
834,998

 
$
120,147

 
$
1,396

 
$
—

 
$
956,541

Intersegment revenues
 
419

 
498

 
—

 
(917
)
 
—

Total revenues
 
$
835,417

 
$
120,645

 
$
1,396

 
$
(917
)
 
$
956,541

 
 
 
 
 
 
 
 
 
 
 
Depreciation and amortization
 
$
77,036

 
$
14,034

 
$
175

 
$
—

 
$
91,245

Interest charges and financing costs
 
26,494

 
2,637

 
90

 
—

 
29,221

Income tax expense
 
40,654

 
2,501

 
1,083

 
—

 
44,238

Net income
 
69,398

 
4,862

 
376

 
—

 
74,636

(Thousands of Dollars)
 
Regulated
Electric
 
Regulated
Natural Gas
 
All Other
 
Reconciling
Eliminations
 
Consolidated
Total
2014
 
 
 
 
 
 
 
 
 
 
Operating revenues (a)
 
$
829,748

 
$
169,629

 
$
1,085

 
$
—

 
$
1,000,462

Intersegment revenues
 
497

 
4,885

 
—

 
(5,382
)
 
—

Total revenues
 
$
830,245

 
$
174,514

 
$
1,085

 
$
(5,382
)
 
$
1,000,462

 
 
 
 
 
 
 
 
 
 
 
Depreciation and amortization
 
$
65,978

 
$
13,501

 
$
175

 
$
—

 
$
79,654

Interest charges and financing costs
 
23,448

 
2,358

 
107

 
—

 
25,913

Income tax expense (benefit)
 
39,621

 
5,993

 
(3,211
)
 
—

 
42,403

Net income
 
59,060

 
8,714

 
2,868

 
—

 
70,642


(a) 
Operating revenues include $170 million, $163 million and $145 million of intercompany revenue for the years ended Dec. 31, 2016, 2015 and 2014 respectively. See Note 15 for further discussion of related party transactions by operating segment.
v3.6.0.2
Related Party Transactions (Tables)
 12 Months Ended
Dec. 31, 2016
Related Party Transactions [Abstract]  
Related Party Transactions
The table below contains significant affiliate transactions among the companies and related parties including billings under the Interchange Agreement for the years ended Dec. 31:
(Thousands of Dollars)
 
2016
 
2015
 
2014
Operating revenues:
 
 
 
 
 
 
Electric
 
$
170,483

 
$
163,255

 
$
145,102

Operating expenses:
 
 
 
 
 
 
Purchased power (a)
 
413,615

 
419,028

 
430,666

Transmission expense
 
61,920

 
54,070

 
43,876

Natural gas purchased for resale
 
41

 
45

 
90

Other operating expenses — paid to Xcel Energy Services Inc.
 
106,454

 
93,890

 
84,224

Interest expense
 
4

 
2

 
30


(a) 
Pursuant to orders issued by the PSCW in December 2013 and February 2014, the 2014 amounts do not reflect $5.2 million of purchased power expenses deferred as a regulatory asset and $11.0 million of transmission costs deferred as a regulatory liability billed to NSP-Wisconsin through the Interchange Agreement from NSP-Minnesota.

Accounts receivable and payable with affiliates at Dec. 31 were:
 
 
2016
 
2015
(Thousands of Dollars)
 
Accounts
Receivable
 
Accounts
Payable
 
Accounts
Receivable
 
Accounts
Payable
NSP-Minnesota
 
$
—

 
$
18,567

 
$
—

 
$
18,268

PSCo
 
—

 
974

 
—

 
71

SPS
 
333

 
—

 
71

 
—

Other subsidiaries of Xcel Energy Inc.
 
—

 
9,496

 
—

 
6,199

 
 
$
333

 
$
29,037

 
$
71

 
$
24,538
v3.6.0.2
Summarized Quarterly Financial Data (Unaudited) (Tables)
 12 Months Ended
Dec. 31, 2016
Quarterly Financial Information Disclosure [Abstract]  
Summarized Quarterly Financial Data (Unaudited)
 
 
Quarter Ended
(Thousands of Dollars)
 
March 31, 2016
 
June 30, 2016
 
Sept. 30, 2016
 
Dec. 31, 2016
Operating revenues
 
$
254,850

 
$
219,173

 
$
246,144

 
$
237,066

Operating income
 
35,448

 
27,778

 
46,342

 
30,360

Net income
 
17,631

 
12,625

 
24,221

 
14,658

 
 
Quarter Ended
(Thousands of Dollars)
 
March 31, 2015
 
June 30, 2015
 
Sept. 30, 2015
 
Dec. 31, 2015
Operating revenues
 
$
273,960

 
$
216,813

 
$
236,161

 
$
229,607

Operating income
 
39,549

 
25,069

 
47,532

 
27,809

Net income
 
22,267

 
12,512

 
26,232

 
13,625
v3.6.0.2
Summary of Significant Accounting Policies (Details)
 12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Accounting Policies [Abstract]      
Percentage of Average Annual Operating Revenues 1.20%    
Average Annual Operating Revenues 3 years    
Property, Plant and Equipment [Abstract]      
Depreciation expense expressed as a percentage of average depreciable property 3.30% 3.40% 3.30%
Cash and Cash Equivalents [Abstract]      
Maximum number of months of remaining maturity at time of purchase to consider investments in certain instruments as cash equivalents 3 months    
v3.6.0.2
Accounting Pronouncements Adoption of New Accounting Pronouncements (Details)
$ in Millions
Dec. 31, 2015
USD ($)
Accounting Standards Update 2015-03 | Long-term Debt  
New Accounting Pronouncements or Change in Accounting Principle [Line Items]  
Reclassification of deferred debt issuance costs, net $ 5.1
Accounting Standards Update 2015-03 | Other Noncurrent Assets  
New Accounting Pronouncements or Change in Accounting Principle [Line Items]  
Reclassification of deferred debt issuance costs, net (5.1)
Accounting Standards Update 2015-17  
New Accounting Pronouncements or Change in Accounting Principle [Line Items]  
Deferred Income Tax Liabilities, Net $ 2.5
v3.6.0.2
Selected Balance Sheet Data, Accounts Receivable (Details) - USD ($)
$ in Thousands
Dec. 31, 2016
Dec. 31, 2015
Accounts Receivable, Net    
Accounts receivable $ 58,896 $ 61,506
Less allowance for bad debts (4,865) (5,128)
Accounts receivable, net [1] $ 54,031 $ 56,378
[1] Accounts receivable, net includes an immaterial amount due from affiliates for 2016 and 2015, respectively.
v3.6.0.2
Selected Balance Sheet Data, Inventory (Details) - USD ($)
$ in Thousands
Dec. 31, 2016
Dec. 31, 2015
Public Utilities, Inventory [Line Items]    
Inventories $ 18,309 $ 21,559
Materials and supplies    
Public Utilities, Inventory [Line Items]    
Inventories 6,582 6,785
Fuel    
Public Utilities, Inventory [Line Items]    
Inventories 4,743 6,528
Natural gas    
Public Utilities, Inventory [Line Items]    
Inventories $ 6,984 $ 8,246
v3.6.0.2
Selected Balance Sheet Data, Property, Plant and Equipment (Details) - USD ($)
$ in Thousands
Dec. 31, 2016
Dec. 31, 2015
Public Utility, Property, Plant and Equipment [Line Items]    
Property, Plant and Equipment, Gross $ 3,069,525 $ 2,885,022
Less accumulated depreciation (1,121,888) (1,056,943)
Property, plant and equipment, net 1,947,637 1,828,079
Electric plant    
Public Utility, Property, Plant and Equipment [Line Items]    
Property, Plant and Equipment, Gross 2,499,401 2,411,562
Natural gas plant    
Public Utility, Property, Plant and Equipment [Line Items]    
Property, Plant and Equipment, Gross 294,986 275,376
Common and other property    
Public Utility, Property, Plant and Equipment [Line Items]    
Property, Plant and Equipment, Gross 156,316 132,329
CWIP    
Public Utility, Property, Plant and Equipment [Line Items]    
Property, Plant and Equipment, Gross $ 118,822 $ 65,755
v3.6.0.2
Borrowings and Other Financing Instruments, Commercial Paper (Details) - USD ($)
$ in Thousands
 3 Months Ended 12 Months Ended
Dec. 31, 2016
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Short-term Debt [Line Items]        
Amount outstanding at period end $ 60,000 $ 60,000 $ 10,000  
Commercial Paper        
Short-term Debt [Line Items]        
Borrowing limit 150,000 150,000 150,000 $ 150,000
Amount outstanding at period end 60,000 60,000 10,000 78,000
Average amount outstanding 32,000 15,000 39,000 46,000
Maximum amount outstanding $ 64,000 $ 64,000 $ 122,000 $ 101,000
Weighted average interest rate, computed on a daily basis (percentage) 0.73% 0.69% 0.44% 0.27%
Weighted average interest rate at period end (percentage) 0.95% 0.95% 0.70% 0.55%
v3.6.0.2
Borrowings and Other Financing Instruments, Letters of Credit (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Line of Credit Facility [Line Items]    
Amount outstanding at period end $ 60,000 $ 10,000
Letter of Credit    
Line of Credit Facility [Line Items]    
Amount outstanding at period end $ 0 $ 0
Letter of Credit | Letter of Credit    
Line of Credit Facility [Line Items]    
Term of letters of credit (in years) 1 year  
v3.6.0.2
Borrowings and Other Financing Instruments, Credit Facility (Details)
 12 Months Ended
Dec. 31, 2016
USD ($)
Dec. 31, 2015
USD ($)
Line of Credit Facility [Line Items]    
Line Of Credit Facility Maximum Debt To Total Capitalization Ratio Allowed 65.00%  
Line Of Credit Facility Debt To Total Capitalization Ratio (as a percent) 47.00% 46.00%
Line Of Credit Facility Minimum Threshhold Percentage Of Subsidiary Assets To Consolidated Assets Required To Initiate Cross Default Provisions 15.00%  
Line of Credit Facility, Minimum Amount of Indebtedness in Default to Initiate Cross Default Provisions $ 75,000,000  
Direct advances on the credit facility outstanding 0 $ 0
Credit Facility    
Line of Credit Facility [Line Items]    
Credit facility [1] 150,000,000  
Drawn [2] 60,000,000  
Available $ 90,000,000  
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 year  
[1] This credit facility matures in June 2021.
[2] Includes outstanding commercial paper.
v3.6.0.2
Borrowings and Other Financing Instruments Borrowings and Other Financing Instruments, Amended Credit Agreements (Details) - Credit Facility
 12 Months Ended
Dec. 31, 2016
USD ($)
Line of Credit Facility [Line Items]  
Borrowing limit $ 150,000,000 [1]
NSP-Wisconsin  
Line of Credit Facility [Line Items]  
Debt Instrument, Term 5 years
NSP-Wisconsin | Original Terms and Conditions [Member]  
Line of Credit Facility [Line Items]  
Maturity Date Oct. 31, 2019
Debt Instrument, Term 5 years
Line Of Credit Facility Minimum Borrowing Margin Based On Long Term Credit Ratings 0.875%
Line Of Credit Facility Maximum Borrowing Margin Based On Long Term Credit Ratings 1.75%
Line Of Credit Facility Minimum Commitment Fees Calculated On Unused Portion Of Lines Of Credit 0.075%
Line Of Credit Facility Maximum Commitment Fees Calculated On Unused Portion Of Lines Of Credit 0.275%
NSP-Wisconsin | Amended Terms and Conditions [Member]  
Line of Credit Facility [Line Items]  
Maturity Date Jun. 30, 2021
Line Of Credit Facility Minimum Borrowing Margin Based On Long Term Credit Ratings 0.75%
Line Of Credit Facility Maximum Borrowing Margin Based On Long Term Credit Ratings 1.50%
Line Of Credit Facility Minimum Commitment Fees Calculated On Unused Portion Of Lines Of Credit 0.06%
Line Of Credit Facility Maximum Commitment Fees Calculated On Unused Portion Of Lines Of Credit 0.225%
[1] This credit facility matures in June 2021.
v3.6.0.2
Borrowings and Other Financing Instruments, Intercompany Borrowing Arrangements and Other Short-Term Borrowings (Details) - USD ($)
$ in Thousands
Dec. 31, 2016
Dec. 31, 2015
Short-term Debt [Line Items]    
Notes payable to affiliates $ 500 $ 500
Notes Payable, Other Payables    
Short-term Debt [Line Items]    
Notes payable to affiliates $ 500 $ 500
Weighted average interest rate at period end (percentage) 0.95% 0.87%
v3.6.0.2
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, 2016
Dec. 31, 2015
Debt Instrument [Line Items]    
Deferred Finance Costs, Noncurrent, Net $ 4.7 $ 5.1
Maximum annual dividends that can be paid if equity capitalization ratio condition is not met $ 53.1  
Minimum calendar year average equity to total capitalization ratio authorized by state commission 52.50%  
Calendar year average equity to total capitalization ratio 53.60%  
Unrestricted Retained Earnings Per State Regulatory Commissions Dividend Restrictions $ 33.6  
First Mortgage Bonds | Series Due June 15, 2024    
Debt Instrument [Line Items]    
Interest Rate, Stated Percentage 3.30% 3.30%
Maturity Date Jun. 15, 2024 Jun. 15, 2024
First Mortgage Bonds | Series Due Oct. 1, 2018    
Debt Instrument [Line Items]    
Interest Rate, Stated Percentage 5.25% 5.25%
Maturity Date Oct. 01, 2018 Oct. 01, 2018
Long-term Debt, Maturities, Repayments of Principal in Year Two $ 150.0  
City of La Crosse Resource Recovery Bond | Series Due Nov. 1, 2021    
Debt Instrument [Line Items]    
Interest Rate, Stated Percentage 6.00% 6.00%
Maturity Date Nov. 01, 2021 Nov. 01, 2021
Long-term Debt, Maturities, Repayments of Principal in Year Five [1] $ 18.6  
NSP-Wisconsin | First Mortgage Bonds | Series Due June 15, 2024    
Debt Instrument [Line Items]    
Face Amount   $ 100.0
Interest Rate, Stated Percentage   3.30%
Maturity Date   Jun. 15, 2024
[1] Resource recovery financing
v3.6.0.2
Joint Ownership of Transmission Facilities (Details)
$ in Thousands
Dec. 31, 2016
USD ($)
Jointly Owned Utility Plant [Abstract]  
Plant in service $ 164,040
Accumulated depreciation 10,874
Construction work in progress 83,677
CapX2020 Transmission | Electric Transmission  
Jointly Owned Utility Plant [Abstract]  
Plant in service 164,040
Accumulated depreciation 10,874
Construction work in progress $ 42,546
Ownership % (in hundredths) 81.00%
La Crosse, Wis. to Madison, Wis. | Electric Transmission  
Jointly Owned Utility Plant [Abstract]  
Plant in service $ 0
Accumulated depreciation 0
Construction work in progress $ 41,131
Ownership % (in hundredths) 37.00%
v3.6.0.2
Income Taxes (Details)
 1 Months Ended 3 Months Ended 12 Months Ended
Aug. 31, 2016
Sep. 30, 2015
Dec. 31, 2016
USD ($)
Dec. 31, 2015
USD ($)
Dec. 31, 2014
USD ($)
Dec. 31, 2012
Dec. 31, 2016
USD ($)
$ / kWh
Dec. 31, 2015
USD ($)
Dec. 31, 2014
USD ($)
Consolidated Appropriations Act of 2016 [Abstract]                  
Excise Tax Delay     2 years            
Earliest Open Tax Year Subject To Examination     2012            
Unrecognized Tax Benefits [Abstract]                  
Unrecognized Tax Benefits - Permanent tax positions             $ 400,000 $ 200,000  
Unrecognized tax benefit — Temporary tax positions             4,900,000 4,300,000  
Total unrecognized tax benefit     $ 4,500,000 $ 3,000,000 $ 1,500,000   5,300,000 4,500,000 $ 3,000,000
Tax Increase Prevention Act of 2014 [Abstract]                  
Number of years bonus depreciation was extended       1 year          
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]                  
Balance at Jan. 1     4,500,000 $ 3,000,000 1,500,000        
Unrecognized Tax Benefits, Increase Resulting from Current Period Tax Positions     500,000 1,900,000 1,900,000        
Unrecognized Tax Benefits, Decrease Resulting from Current Period Tax Positions     0 (300,000) (200,000)        
Unrecognized Tax Benefits Increases Resulting From Prior Period Tax Positions     500,000 800,000 100,000        
Unrecognized Tax Benefits Decreases Resulting From Prior Period Tax Positions     (200,000) (900,000) (200,000)        
Unrecognized Tax Benefits, Decrease Resulting from Settlements with Taxing Authorities     0 0 (100,000)        
Balance at Dec. 31     $ 5,300,000 $ 4,500,000 $ 3,000,000        
Tax Benefits Associated With NOL And Tax Credit Carryforwards [Abstract]                  
NOL and tax credit carryforwards             (1,200,000) (900,000)  
Decrease in Unrecognized Tax Benefits is Reasonably Possible             2,000,000    
Amounts accrued for penalties related to unrecognized tax benefits             0 0 $ 0
Effective Income Tax Rate Reconciliation, Percent [Abstract]                  
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent     35.00% 35.00% 35.00%        
Effective Income Tax Rate Reconciliation, State and Local Income Taxes, Percent     4.90% 4.80% 4.90%        
Effective Income Tax Rate Reconciliation Change In Unrecognized Tax Benefits, Percent     0.10% 0.10% 0.00%        
Effective Income Tax Rate Reconciliation, Tax Credit, Percent     (0.70%) (0.70%) (0.70%)        
Effective Income Tax Rate Reconciliation Regulatory Differences Utility Plant Items, Percent     (0.70%) (1.70%) (1.60%)        
Effective Income Tax Rate Reconciliation, Other Adjustments, Percent     (0.30%) (0.30%) (0.10%)        
Effective Income Tax Rate Reconciliation, Percent     38.30% 37.20% 37.50%        
Components of Income Tax Expense (Benefit), Continuing Operations [Abstract]                  
Current Federal Tax Expense (Benefit)     $ 5,367,000 $ (4,715,000) $ (3,932,000)        
Current State and Local Tax Expense (Benefit)     131,000 2,150,000 453,000        
Current Change In Unrecognized Tax Expense (Benefit)     559,000 1,498,000 1,013,000        
Deferred Federal Income Tax Expense (Benefit)     29,588,000 40,580,000 38,321,000        
Deferred State and Local Income Tax Expense (Benefit)     8,212,000 6,675,000 8,042,000        
Deferred Change In Unrecognized Tax Expense (Benefit)     (432,000) (1,422,000) (967,000)        
Deferred investment tax credits     (523,000) (528,000) (527,000)        
Income Tax Expense (Benefit)     42,902,000 44,238,000 42,403,000        
Deferred Income Tax Expense (Benefit), Continuing Operations [Abstract]                  
Deferred tax expense (benefit) excluding selected items     39,530,000 51,084,000 49,793,000        
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities     (2,112,000) (5,200,000) (4,346,000)        
Other Comprehensive Income (Loss), Tax     (50,000) (51,000) (51,000)        
Deferred Income Tax Expense (Benefit)     37,368,000 $ 45,833,000 $ 45,396,000        
Deferred Tax Liabilities, Gross [Abstract]                  
Deferred Tax Liabilities, Property, Plant and Equipment             412,071,000 382,592,000  
Deferred Tax Liabilities, Regulatory Assets             75,392,000 78,233,000  
Deferred Tax Liabilities, Compensation and Benefits, Employee Benefits             15,443,000 18,028,000  
Deferred Tax Liabilities, Other             9,949,000 10,190,000  
Deferred Tax Liabilities, Gross             512,855,000 489,043,000  
Deferred Tax Assets, Gross [Abstract]                  
Deferred Tax Assets, Operating Loss Carryforwards             35,216,000 37,508,000  
Deferred Tax Assets Environmental Remediation             25,842,000 37,938,000  
Deferred Tax Assets Regulatory Liabilities             5,779,000 9,328,000  
Deferred Tax Assets Deferred Investment Tax Credits             4,996,000 5,312,000  
Deferred Tax Assets Tax credit carryforward             3,704,000 4,760,000  
Deferred Tax Assets, Other             6,725,000 3,134,000  
Deferred Tax Assets, Net of Valuation Allowance             82,262,000 97,980,000  
Deferred Tax Liabilities, Net             430,593,000 391,063,000  
Internal Revenue Service (IRS)                  
Tax Audits [Abstract]                  
Year(s) under examination   2012 and 2013.       2010 and 2011      
Year of carryback claim under examination           2009      
Tax Adjustments, Settlements, and Unusual Provisions     $ 14,000,000            
Operating Loss Carryforwards             97,000,000 103,000,000  
Tax Credit Carryforward, Amount             4,000,000 5,000,000  
Carryforward expiration date range, low     2021            
Carryforward expiration date range, high     2036            
WISCONSIN                  
Tax Audits [Abstract]                  
Year(s) under examination 2012 and 2013                
State and Local Jurisdiction                  
Tax Audits [Abstract]                  
Operating Loss Carryforwards             $ 3,000,000 $ 3,000,000  
Carryforward expiration date range, high     2031            
Consolidated Appropriations Act of 2016; 2015, 2016, 2017 Impact [Member]                  
Consolidated Appropriations Act of 2016 [Abstract]                  
Bonus depreciation rate, Percent             50.00%    
Consolidated Appropriations Act of 2016; 2018 Impact [Member]                  
Consolidated Appropriations Act of 2016 [Abstract]                  
Bonus depreciation rate, Percent             40.00%    
Production Tax Credit Rate, Percent             60.00%    
Consolidated Appropriations Act of 2016; 2019 Impact [Member]                  
Consolidated Appropriations Act of 2016 [Abstract]                  
Bonus depreciation rate, Percent             30.00%    
Production Tax Credit Rate, Percent             40.00%    
Investment Tax Credit Rate, Percent             30.00%    
Consolidated Appropriations Act of 2016; 2016 Impact [Member]                  
Consolidated Appropriations Act of 2016 [Abstract]                  
Production Tax Credit Rate, Percent             100.00%    
Production Tax Credit per KWh | $ / kWh             0.023    
Consolidated Appropriations Act of 2016; 2017 Impact [Member]                  
Consolidated Appropriations Act of 2016 [Abstract]                  
Production Tax Credit Rate, Percent             80.00%    
Consolidated Appropriations Act of 2016; 2020 Impact [Member]                  
Consolidated Appropriations Act of 2016 [Abstract]                  
Investment Tax Credit Rate, Percent             26.00%    
Consolidated Appropriations Act of 2016; 2021 Impact [Member]                  
Consolidated Appropriations Act of 2016 [Abstract]                  
Investment Tax Credit Rate, Percent             22.00%    
Consolidated Appropriations Act of 2016; After 2021 Impact [Member]                  
Consolidated Appropriations Act of 2016 [Abstract]                  
Investment Tax Credit Rate, Percent             10.00%    
Tax Increase Prevention Act of 2014; 2014 Impact [Member]                  
Consolidated Appropriations Act of 2016 [Abstract]                  
Bonus depreciation rate, Percent               50.00%  
Tax Increase Prevention Act of 2014; 2015 Impact [Member]                  
Consolidated Appropriations Act of 2016 [Abstract]                  
Bonus depreciation rate, Percent             50.00%    
v3.6.0.2
Benefit Plans and Other Postretirement Benefits, Employees Represented by Local Labor Unions (Details)
Dec. 31, 2016
Employee
Employees Represented by Local Labor Unions Under Collective Bargaining Agreements Receiving Benefits [Abstract]  
Approximate percent of employees receiving benefits who are represented by local labor unions under collective bargaining agreements (as a percent) 71.00%
Number of bargaining employees receiving benefits under several collective bargaining agreements 399
v3.6.0.2
Benefit Plans and Other Postretirement Benefits Benefits Plans and Other Postretirement Benefits, Fair Value Hierarchy (Details)
 12 Months Ended
Dec. 31, 2016
Commingled funds | Maximum  
Defined Benefit Plan Disclosure [Line Items]  
Notice period for investment redemption 90 days
Real estate funds | Minimum  
Defined Benefit Plan Disclosure [Line Items]  
Notice period for investment redemption 45 days
Real estate funds | Maximum  
Defined Benefit Plan Disclosure [Line Items]  
Notice period for investment redemption 90 days
v3.6.0.2
Benefit Plans and Other Postretirement Benefits, Pension Benefits (Details) - USD ($)
$ in Thousands
 1 Months Ended 12 Months Ended
Jan. 31, 2017
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Supplemental Executive Retirement Plan (SERP) and Nonqualified Pension Plan        
Pension Benefits [Abstract]        
Total benefit obligation   $ 800 $ 700  
Net benefit cost recognized for financial reporting   7,900 9,500  
Pension Plans        
Defined Benefit Plan Disclosure [Line Items]        
Total contributions to Xcel Energy's pension plans during the period   7,400 4,900 $ 8,000
Pension Benefits [Abstract]        
Total benefit obligation   157,457 152,545 165,669
Net benefit cost recognized for financial reporting   $ 7,579 $ 8,711 $ 8,870
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% 7.25% 7.25%
Expected average long-term rate of return on assets for next fiscal year (as a percent)   7.10%    
Target Pension Asset Allocations [Abstract]        
Target pension asset allocations (as a percent)   100.00% 100.00%  
Pension Plans | Domestic and international equity securities        
Target Pension Asset Allocations [Abstract]        
Target pension asset allocations (as a percent)   40.00% 41.00%  
Pension Plans | Long-duration fixed income and interest rate swap securities        
Target Pension Asset Allocations [Abstract]        
Target pension asset allocations (as a percent)   23.00% 23.00%  
Pension Plans | Short-to-intermediate fixed income securities        
Target Pension Asset Allocations [Abstract]        
Target pension asset allocations (as a percent)   16.00% 14.00%  
Pension Plans | Alternative investments        
Target Pension Asset Allocations [Abstract]        
Target pension asset allocations (as a percent)   19.00% 20.00%  
Pension Plans | Cash        
Target Pension Asset Allocations [Abstract]        
Target pension asset allocations (as a percent)   2.00% 2.00%  
Xcel Energy Inc. | Supplemental Executive Retirement Plan (SERP) and Nonqualified Pension Plan        
Pension Benefits [Abstract]        
Total benefit obligation   $ 43,500 $ 41,800  
Xcel Energy Inc. | Pension Plans        
Defined Benefit Plan Disclosure [Line Items]        
Total contributions to Xcel Energy's pension plans during the period   $ 125,200 $ 90,100 $ 130,600
Subsequent Event | Pension Plans        
Defined Benefit Plan Disclosure [Line Items]        
Total contributions to Xcel Energy's pension plans during the period $ 9,000      
Subsequent Event | Xcel Energy Inc. | Pension Plans        
Defined Benefit Plan Disclosure [Line Items]        
Total contributions to Xcel Energy's pension plans during the period $ 150,000      
v3.6.0.2
Benefit Plans and Other Postretirement Benefits, Fair Value of Pension Plan Assets (Details) - Pension Plans - USD ($)
$ in Thousands
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets $ 118,976 $ 119,314 $ 132,713
Plan asset investments measured at net asset value 86,628 [1] 85,197 [2]  
Level 1      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 8,158 10,218  
Level 2      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 24,190 23,899  
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 3,939 6,005  
Plan asset investments measured at net asset value 0 [1] 0 [2]  
Cash equivalents | Level 1      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 3,939 6,005  
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  
Derivatives      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets   89  
Plan asset investments measured at net asset value [2]   0  
Derivatives | Level 1      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets   0  
Derivatives | Level 2      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets   89  
Derivatives | Level 3      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets   0  
U.S. equity funds      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 21,415 17,338  
Plan asset investments measured at net asset value 21,415 [1] 17,338 [2]  
U.S. equity funds | Level 1      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 0 0  
U.S. equity funds | Level 2      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 0 0  
U.S. equity funds | Level 3      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 0 0  
Non U.S. equity funds      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 16,348 16,710  
Plan asset investments measured at net asset value 16,348 [1] 16,710 [2]  
Non U.S. equity funds | Level 1      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 0 0  
Non U.S. equity funds | Level 2      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 0 0  
Non U.S. equity funds | Level 3      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 0 0  
U.S. corporate bond funds      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 10,581 10,001  
Plan asset investments measured at net asset value 10,581 [1] 10,001 [2]  
U.S. corporate bond funds | Level 1      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 0 0  
U.S. corporate bond funds | Level 2      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 0 0  
U.S. corporate bond funds | Level 3      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 0 0  
Emerging market equity funds      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 8,577 7,491  
Plan asset investments measured at net asset value 8,577 [1] 7,491 [2]  
Emerging market equity funds | Level 1      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 0 0  
Emerging market equity funds | Level 2      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 0 0  
Emerging market equity funds | Level 3      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 0 0  
Emerging market debt funds      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 7,306 7,245  
Plan asset investments measured at net asset value 7,306 [1] 7,245 [2]  
Emerging market debt funds | Level 1      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 0 0  
Emerging market debt funds | Level 2      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 0 0  
Emerging market debt funds | Level 3      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 0 0  
Commodity funds      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 889 2,461  
Plan asset investments measured at net asset value 889 [1] 2,461 [2]  
Commodity funds | Level 1      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 0 0  
Commodity funds | Level 2      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 0 0  
Commodity funds | Level 3      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 0 0  
Private equity investments      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 4,652 5,967  
Plan asset investments measured at net asset value 4,652 [1] 5,967 [2]  
Private equity investments | Level 1      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 0 0  
Private equity investments | Level 2      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 0 0  
Private equity investments | Level 3      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 0 0  
Real estate      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 8,108 8,663  
Plan asset investments measured at net asset value 8,108 [1] 8,663 [2]  
Real estate | Level 1      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 0 0  
Real estate | Level 2      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 0 0  
Real estate | Level 3      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 0 0  
Other commingled funds      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 8,752 9,321  
Plan asset investments measured at net asset value 8,752 [1] 9,321 [2]  
Other commingled funds | Level 1      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 0 0  
Other commingled funds | Level 2      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 0 0  
Other commingled funds | Level 3      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 0 0  
Government securities      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 12,773 13,048  
Plan asset investments measured at net asset value 0 [1] 0 [2]  
Government securities | Level 1      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 0 0  
Government securities | Level 2      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 12,773 13,048  
Government securities | Level 3      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 0 0  
U.S. corporate bonds      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 9,432 9,008  
Plan asset investments measured at net asset value 0 [1] 0 [2]  
U.S. corporate bonds | Level 1      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 0 0  
U.S. corporate bonds | Level 2      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 9,432 9,008  
U.S. corporate bonds | Level 3      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 0 0  
Non U.S. corporate bonds      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 1,514 1,446  
Plan asset investments measured at net asset value 0 [1] 0 [2]  
Non U.S. corporate bonds | Level 1      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 0 0  
Non U.S. corporate bonds | Level 2      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 1,514 1,446  
Non U.S. corporate bonds | Level 3      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 0 0  
Mortgage-backed securities      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 254    
Plan asset investments measured at net asset value [1] 0    
Mortgage-backed securities | Level 1      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 0    
Mortgage-backed securities | Level 2      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 254    
Mortgage-backed securities | Level 3      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 0    
Asset-backed securities      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 120 101  
Plan asset investments measured at net asset value 0 [1] 0 [2]  
Asset-backed securities | Level 1      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 0 0  
Asset-backed securities | Level 2      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 120 101  
Asset-backed securities | Level 3      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 0 0  
U.S. equities      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 4,219 4,213  
Plan asset investments measured at net asset value 0 [1] 0 [2]  
U.S. equities | Level 1      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 4,219 4,213  
U.S. equities | Level 2      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 0 0  
U.S. equities | Level 3      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 0 0  
Other      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 97 207  
Plan asset investments measured at net asset value 0 [1] 0 [2]  
Other | Level 1      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 0 0  
Other | Level 2      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 97 207  
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  
[1] Based on the requirements of ASU No. 2015-07, investments measured at fair value using a NAV methodology have not been classified in the fair value hierarchy. See Note 2 for further information on the adoption of ASU No. 2015-07.
[2] Based on the requirements of ASU No. 2015-07, investments measured at fair value using a NAV methodology have not been classified in the fair value hierarchy. See Note 2 for further information on the adoption of ASU No. 2015-07.
v3.6.0.2
Benefit Plans and Other Postretirement Benefits, Pension Plan Benefit Obligations, Cash Flows and Benefit Costs (Details)
$ in Thousands
 1 Months Ended 12 Months Ended
Jan. 31, 2017
USD ($)
Dec. 31, 2016
USD ($)
Plan
Dec. 31, 2015
USD ($)
Plan
Dec. 31, 2014
USD ($)
Plan
Significant Assumptions Used to Measure Costs [Abstract]        
Contributions to 401(k) and other defined contribution plans   $ 1,400 $ 1,400 $ 1,400
Pension Plans        
Defined Benefit Plan Disclosure [Line Items]        
Accumulated Benefit Obligation at Dec. 31   146,448 140,917  
Change in Projected Benefit Obligation [Roll Forward]        
Obligation at Jan. 1 $ 157,457 152,545 165,669  
Service cost   4,417 4,759 4,527
Interest cost   6,816 6,520 7,257
Plan amendments   305 0  
Actuarial (gain) loss   7,315 (11,159)  
Benefit payments   (13,941) (13,244)  
Obligation at Dec. 31   157,457 152,545 165,669
Change in Fair Value of Plan Assets [Roll Forward]        
Fair value of plan assets at Jan. 1 118,976 119,314 132,713  
Actual return (loss) on plan assets   6,163 (5,087)  
Employer contributions   7,440 4,932  
Benefit payments   (13,941) (13,244)  
Fair value of plan assets at Dec. 31   118,976 119,314 132,713
Funded Status of Plans at Dec. 31 [Abstract]        
Funded status [1]   (38,481) (33,231)  
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost [Abstract]        
Net loss   91,531 86,614  
Prior service (credit) cost   750 556  
Total   92,281 87,170  
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   5,972 6,300  
Noncurrent regulatory assets   86,309 80,870  
Total   $ 92,281 $ 87,170  
Significant Assumptions Used to Measure Benefit Obligations [Abstract]        
Discount rate for year-end valuation (as a percent)   4.13% 4.66%  
Expected average long-term increase in compensation level (as a percent)   3.75% 4.00%  
Mortality table   RP 2014 RP 2014  
Cash Flows [Abstract]        
Total contributions to Xcel Energy's pension plans during the period   $ 7,400 $ 4,900 8,000
Components of Net Periodic Benefit Cost (Credit) [Abstract]        
Service cost   4,417 4,759 4,527
Interest cost   6,816 6,520 7,257
Expected return on plan assets   (9,157) (9,483) (9,642)
Amortization of prior service cost (credit)   111 111 111
Amortization of net loss   5,392 6,804 6,617
Net periodic benefit cost   $ 7,579 $ 8,711 $ 8,870
Significant Assumptions Used to Measure Costs [Abstract]        
Discount rate (as a percent)   4.66% 4.11% 4.75%
Expected average long-term increase in compensation level (as a percent)   4.00% 3.75% 3.75%
Expected average long-term rate of return on assets (as a percent)   7.10% 7.25% 7.25%
Allocated costs for pension plans sponsored by Xcel Energy Inc.   $ 1,600 $ 1,900 $ 1,700
Expected average long-term rate of return on assets for next fiscal year (as a percent)   7.10%    
Number of years fair market value of plan assets is adjusted using calculated value method (in years)   5 years    
Annual adjustment rate used in calculated value method (as a percent)   20.00%    
Xcel Energy Inc. | Pension Plans        
Cash Flows [Abstract]        
Total contributions to Xcel Energy's pension plans during the period   $ 125,200 $ 90,100 $ 130,600
Number of pension plans to which contributions were made | Plan   4 4 4
Subsequent Event | Pension Plans        
Cash Flows [Abstract]        
Total contributions to Xcel Energy's pension plans during the period 9,000      
Subsequent Event | Xcel Energy Inc. | Pension Plans        
Cash Flows [Abstract]        
Total contributions to Xcel Energy's pension plans during the period $ 150,000      
[1] Amounts are recognized in noncurrent liabilities on NSP-Wisconsin’s consolidated balance sheets.
v3.6.0.2
Benefit Plans and Other Postretirement Benefits, Defined Contribution Plans (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Defined Contribution Plans [Abstract]      
Contributions to 401(k) and other defined contribution plans $ 1.4 $ 1.4 $ 1.4
v3.6.0.2
Benefit Plans and Other Postretirement Benefits, Postretirement Health Care Benefits (Details) - Postretirement Benefit Plan
 12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Postretirement Health Care Benefits [Abstract]    
Target pension asset allocations (as a percent) 100.00% 100.00%
Domestic and international equity securities    
Postretirement Health Care Benefits [Abstract]    
Target pension asset allocations (as a percent) 25.00% 25.00%
Short-to-intermediate fixed income securities    
Postretirement Health Care Benefits [Abstract]    
Target pension asset allocations (as a percent) 57.00% 57.00%
Alternative investments    
Postretirement Health Care Benefits [Abstract]    
Target pension asset allocations (as a percent) 13.00% 13.00%
Cash    
Postretirement Health Care Benefits [Abstract]    
Target pension asset allocations (as a percent) 5.00% 5.00%
v3.6.0.2
Benefit Plans and Other Postretirement Benefits, Fair Value of Postretirement Benefit Plan Assets (Details) - Postretirement Benefit Plan - USD ($)
$ in Thousands
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets $ 543 $ 418 $ 512
Plan assets at net asset value 205 [1] 191 [2]  
Level 1      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 75 18  
Level 2      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 263 209  
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 25 18  
Plan assets at net asset value 0 [1] 0 [2]  
Cash equivalents | Level 1      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 25 18  
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 58 44  
Plan assets at net asset value 0 [1] 0 [2]  
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 58 44  
Insurance contracts | Level 3      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 0 0  
U.S. equity funds      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 67 36  
Plan assets at net asset value 67 [1] 36 [2]  
U.S. equity funds | Level 1      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 0 0  
U.S. equity funds | Level 2      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 0 0  
U.S. equity funds | Level 3      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 0 0  
Non U.S. equity funds      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets   31  
Plan assets at net asset value [2]   31  
Non U.S. equity funds | Level 1      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets   0  
Non U.S. equity funds | Level 2      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets   0  
Non U.S. equity funds | Level 3      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets   0  
U.S fixed income funds      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 33 23  
Plan assets at net asset value 33 [1] 23 [2]  
U.S fixed income funds | Level 1      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 0 0  
U.S fixed income funds | Level 2      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 0 0  
U.S fixed income funds | Level 3      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 0 0  
Emerging market equity funds      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets   10  
Plan assets at net asset value [2]   10  
Emerging market equity funds | Level 1      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets   0  
Emerging market equity funds | Level 2      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets   0  
Emerging market equity funds | Level 3      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets   0  
Emerging market debt funds      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 38 33  
Plan assets at net asset value 38 [1] 33 [2]  
Emerging market debt funds | Level 1      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 0 0  
Emerging market debt funds | Level 2      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 0 0  
Emerging market debt funds | Level 3      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 0 0  
Other commingled funds      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 67 58  
Plan assets at net asset value 67 [1] 58 [2]  
Other commingled funds | Level 1      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 0 0  
Other commingled funds | Level 2      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 0 0  
Other commingled funds | Level 3      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 0 0  
Government securities      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 46 37  
Plan assets at net asset value 0 [1] 0 [2]  
Government securities | Level 1      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 0 0  
Government securities | Level 2      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 46 37  
Government securities | Level 3      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 0 0  
U.S. corporate bonds      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 77 56  
Plan assets at net asset value 0 [1] 0 [2]  
U.S. corporate bonds | Level 1      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 0 0  
U.S. corporate bonds | Level 2      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 77 56  
U.S. corporate bonds | Level 3      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 0 0  
Non U.S. corporate bonds      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 21 12  
Plan assets at net asset value 0 [1] 0 [2]  
Non U.S. corporate bonds | Level 1      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 0 0  
Non U.S. corporate bonds | Level 2      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 21 12  
Non U.S. corporate bonds | Level 3      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 0 0  
Asset-backed securities      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 23 27  
Plan assets at net asset value 0 [1] 0 [2]  
Asset-backed securities | Level 1      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 0 0  
Asset-backed securities | Level 2      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 23 27  
Asset-backed securities | Level 3      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 0 0  
Mortgage-backed securities      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 36 33  
Plan assets at net asset value 0 [1] 0 [2]  
Mortgage-backed securities | Level 1      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 0 0  
Mortgage-backed securities | Level 2      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 36 33  
Mortgage-backed securities | Level 3      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 0 $ 0  
Non U.S. equities      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 50    
Plan assets at net asset value [1] 0    
Non U.S. equities | Level 1      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 50    
Non U.S. equities | Level 2      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 0    
Non U.S. equities | Level 3      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 0    
Other      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 2    
Plan assets at net asset value [1] 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    
Other | Level 2      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets 2    
Other | Level 3      
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]      
Fair value of plan assets $ 0    
[1] Based on the requirements of ASU No. 2015-07, investments measured at fair value using a NAV methodology have not been classified in the fair value hierarchy. See Note 2 for further information on the adoption of ASU No. 2015-07.
[2] Based on the requirements of ASU No. 2015-07, investments measured at fair value using a NAV methodology have not been classified in the fair value hierarchy. See Note 2 for further information on the adoption of ASU No. 2015-07.
v3.6.0.2
Benefit Plans and Other Postretirement Benefits, Postretirement Benefit Plan Benefit Obligations, Cash Flows and Benefit Costs (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Funded Status of Plans at Dec. 31 [Abstract]      
Noncurrent liabilities $ (55,164) $ (49,889)  
Postretirement Benefit Plan      
Change in Projected Benefit Obligation [Roll Forward]      
Obligation at Jan. 1 14,718 16,768  
Service cost 24 29 $ 35
Interest cost 651 653 791
Medicare subsidy reimbursements 7 13  
Plan participants' contributions 87 130  
Actuarial (gain) loss 775 (1,645)  
Benefit payments (1,289) (1,230)  
Obligation at Dec. 31 14,973 14,718 16,768
Change in Fair Value of Plan Assets [Roll Forward]      
Fair value of plan assets at Jan. 1 418 512  
Actual return (loss) on plan assets (12) (12)  
Plan participants' contributions 87 130  
Employer contributions 1,339 1,018  
Benefit payments (1,289) (1,230)  
Fair value of plan assets at Dec. 31 543 418 512
Funded Status of Plans at Dec. 31 [Abstract]      
Funded status (14,430) (14,300)  
Current liabilities (822) (1,017)  
Noncurrent liabilities (13,608) (13,283)  
Net postretirement amounts recognized on consolidated balance sheets (14,430) (14,300)  
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost [Abstract]      
Net loss 8,883 8,402  
Prior service (credit) cost (2,134) (2,485)  
Total 6,749 5,917  
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 99  
Noncurrent regulatory assets 6,749 5,818  
Total $ 6,749 $ 5,917  
Significant Assumptions Used to Measure Benefit Obligations [Abstract]      
Discount rate for year-end valuation (as a percent) 4.13% 4.65%  
Mortality table RP 2014 RP 2014  
Health care costs trend rate - initial (as a percent) 5.50% 6.00%  
Ultimate health care trend assumption rate (as a percent) 4.50%    
Period until ultimate trend rate is reached (in years) 2 years    
Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rate [Abstract]      
One-percent increase in APBO $ 1,423    
One-percent decrease in APBO (1,212)    
One-percent increase in service and interest components 71    
One-percent decrease in service and interest components (60)    
Cash Flows [Abstract]      
Total contributions to Xcel Energy's postretirement health care plans during the year 1,300 $ 1,000 1,000
Expected contribution to postretirement health care plans during 2017 1,400    
Components of Net Periodic Benefit Cost (Credit) [Abstract]      
Service cost 24 29 35
Interest cost 651 653 791
Expected return on plan assets (24) (30) (52)
Amortization of prior service cost (credit) (351) (351) (351)
Amortization of net loss 330 456 666
Net periodic benefit cost $ 630 $ 757 $ 1,089
Significant Assumptions Used to Measure Costs [Abstract]      
Discount rate (as a percent) 4.65% 4.08% 4.82%
Expected average long-term rate of return on assets (as a percent) 5.80% 5.80% 7.08%
Xcel Energy Inc. | Postretirement Benefit Plan      
Cash Flows [Abstract]      
Total contributions to Xcel Energy's postretirement health care plans during the year $ 17,900 $ 18,300 $ 17,100
Expected contribution to postretirement health care plans during 2017 $ 11,800    
v3.6.0.2
Benefit Plans and Other Postretirement Benefits, Projected Benefit Payments (Details)
$ in Thousands
Dec. 31, 2016
USD ($)
Pension Plans  
Defined Benefit Plan, Gross Projected Benefit Payments [Abstract]  
2017 $ 12,324
2018 11,496
2019 12,957
2020 13,329
2021 12,964
2022-2026 61,280
Postretirement Benefit Plan  
Defined Benefit Plan, Gross Projected Benefit Payments [Abstract]  
2017 1,371
2018 1,308
2019 1,271
2020 1,226
2021 1,169
2022-2026 5,031
Expected Medicare Part D Subsidies [Abstract]  
2017 6
2018 5
2019 4
2020 4
2021 3
2022-2026 15
Defined Benefit Plan, Net Projected Benefit Payments [Abstract]  
2017 1,365
2018 1,303
2019 1,267
2020 1,222
2021 1,166
2022-2026 $ 5,016
v3.6.0.2
Benefit Plans and Other Postretirement Benefits, Multiemployer Plans (Details)
$ in Thousands
 12 Months Ended
Dec. 31, 2016
USD ($)
Employer
Dec. 31, 2015
USD ($)
Dec. 31, 2014
USD ($)
Multiemployer Plans [Abstract]      
Number of employers that must be exceeded during a given period in order for certain union workers to participate in multiemployer plans | Employer 1    
Multiemployer Pension Plans      
Multiemployer Plans [Abstract]      
Multiemployer contributions | $ $ 707 $ 944 $ 156
v3.6.0.2
Other Income, Net (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Other Income and Expenses [Abstract]      
Interest income $ 244 $ 332 $ 368
Other nonoperating income 208 789 321
Insurance Policy Expense (Income), Net 22 (228) (409)
Other nonoperating expense (13) (10) (10)
Other income, net $ 461 $ 883 $ 270
v3.6.0.2
Fair Value of Financial Assets and Liabilities, Derivative Instruments (Details)
MMBTU in Thousands, $ in Millions
Dec. 31, 2016
USD ($)
MMBTU
Dec. 31, 2015
MMBTU
Interest Rate Swap    
Interest Rate Derivatives [Abstract]    
Amount of accumulated other comprehensive gains (losses) related to interest rate derivatives expected to be reclassified into earnings within the next twelve months | $ $ (0.1)  
Natural Gas Commodity (in million British thermal units)    
Gross Notional Amounts of Commodity Options [Abstract]    
Derivative, Nonmonetary Notional amount | MMBTU [1],[2] 255 388
[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.
v3.6.0.2
Fair Value of Financial Assets and Liabilities, Financial Impact of Qualifying Cash Flow Hedges (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
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 $ (209) $ (285) $ (361)
After-tax net realized losses on derivative transactions reclassified into earnings 76 76 76
Accumulated other comprehensive loss related to cash flow hedges at Dec. 31 $ (133) $ (209) $ (285)
v3.6.0.2
Fair Value of Financial Assets and Liabilities, Impact of Derivative Activity (Details) - USD ($)
 12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Financial Impact of Qualifying Fair Value Hedges on Earnings [Abstract]      
Derivative instruments designated as fair value hedges $ 0 $ 0 $ 0
Recognized gains (losses) from fair value hedges or related hedged transactions 0 0 0
Designated as Hedging Instrument | Cash Flow Hedges | Interest Rate      
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract]      
Interest Rate Cash Flow Hedge Gain (Loss) Reclassified to Earnings, Net (100,000) (100,000) (100,000)
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 (200,000) (700,000) $ 100,000
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities) $ 800,000 $ 1,400,000  
v3.6.0.2
Fair Value of Financial Assets and Liabilities, Derivative Assets and Liabilities at Fair Value (Details) - USD ($)
$ in Thousands
Dec. 31, 2016
Dec. 31, 2015
Derivatives, Fair Value [Line Items]    
Prepayments and other $ 3,785 $ 2,387
Other current liabilities 26,484 15,146
Fair Value Measured on a Recurring Basis | Other Current Assets    
Derivatives, Fair Value [Line Items]    
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset [1]   (11)
Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments    
Derivatives, Fair Value [Line Items]    
Derivative Asset, Fair Value, Gross Asset [2]   4
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 149 [3] 4
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset [1] 0 (11)
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments    
Derivatives, Fair Value [Line Items]    
Derivative Liability, Fair Value, Gross Liability [2]   183
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset [1]   (11)
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Natural Gas Commodity    
Derivatives, Fair Value [Line Items]    
Derivative Liability, Fair Value, Gross Liability   183
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset [1]   (11)
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Assets | Other Derivative Instruments    
Derivatives, Fair Value [Line Items]    
Derivative Asset, Fair Value, Gross Asset   0
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Assets | Other Derivative Instruments | Natural Gas Commodity    
Derivatives, Fair Value [Line Items]    
Derivative Asset, Fair Value, Gross Asset 0 0
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Liabilities | Other Derivative Instruments    
Derivatives, Fair Value [Line Items]    
Derivative Liability, Fair Value, Gross Liability   0
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Liabilities | Other Derivative Instruments | Natural Gas Commodity    
Derivatives, Fair Value [Line Items]    
Derivative Liability, Fair Value, Gross Liability   0
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Assets | Other Derivative Instruments    
Derivatives, Fair Value [Line Items]    
Derivative Asset, Fair Value, Gross Asset   15
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 149 15
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Liabilities | Other Derivative Instruments    
Derivatives, Fair Value [Line Items]    
Derivative Liability, Fair Value, Gross Liability   194
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Liabilities | Other Derivative Instruments | Natural Gas Commodity    
Derivatives, Fair Value [Line Items]    
Derivative Liability, Fair Value, Gross Liability   194
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Assets | Other Derivative Instruments    
Derivatives, Fair Value [Line Items]    
Derivative Asset, Fair Value, Gross Asset   0
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Assets | Other Derivative Instruments | Natural Gas Commodity    
Derivatives, Fair Value [Line Items]    
Derivative Asset, Fair Value, Gross Asset 0 0
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Liabilities | Other Derivative Instruments    
Derivatives, Fair Value [Line Items]    
Derivative Liability, Fair Value, Gross Liability   0
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Liabilities | Other Derivative Instruments | Natural Gas Commodity    
Derivatives, Fair Value [Line Items]    
Derivative Liability, Fair Value, Gross Liability   0
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis    
Derivatives, Fair Value [Line Items]    
Prepayments and other 3,800 2,400
Other current liabilities   15,100
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Current Assets    
Derivatives, Fair Value [Line Items]    
Derivative Asset, Fair Value, Gross Asset   15
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 $ 149 15
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments    
Derivatives, Fair Value [Line Items]    
Derivative Liability, Fair Value, Gross Liability   194
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Natural Gas Commodity    
Derivatives, Fair Value [Line Items]    
Derivative Liability, Fair Value, Gross Liability   $ 194
[1] 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, 2016 and 2015. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.
[2] Included in prepayments and other current assets balance of $2.4 million and other current liabilities balance of $15.1 million at Dec. 31, 2015 in the consolidated balance sheets.
[3] Included in prepayments and other current assets balance of $3.8 million at Dec. 31, 2016 in the consolidated balance sheets.
v3.6.0.2
Fair Value of Financial Assets and Liabilities, Fair Value of Long-Term Debt (Details) - USD ($)
$ in Thousands
Dec. 31, 2016
Dec. 31, 2015
Carrying Amount    
Financial Liabilities, Balance Sheet Groupings [Abstract]    
Long-term debt, including current portion (a) $ 663,069 $ 662,449
Fair Value    
Financial Liabilities, Balance Sheet Groupings [Abstract]    
Long-term debt, including current portion (a) $ 730,284 $ 742,565
v3.6.0.2
Rate Matters Rate Matters (Details)
 1 Months Ended 3 Months Ended 12 Months Ended
Sep. 28, 2016
Jun. 30, 2016
Dec. 31, 2016
USD ($)
Oct. 31, 2016
USD ($)
Jul. 31, 2016
USD ($)
Apr. 30, 2016
USD ($)
Mar. 31, 2015
USD ($)
Feb. 28, 2015
Nov. 30, 2013
Mar. 31, 2015
USD ($)
Dec. 31, 2016
USD ($)
Dec. 31, 2015
USD ($)
MW
Dec. 31, 2014
USD ($)
Dec. 31, 2013
USD ($)
Dec. 31, 2008
USD ($)
Public Utilities, General Disclosures [Line Items]                              
Loss on Monticello life cycle management/extended power uprate project                     $ 0 $ 5,237,000 $ 0    
NSP-Wisconsin | PSCW Proceeding - Wisconsin 2017 Electric and Gas Rate Case - Electric Rates 2017                              
Public Utilities, General Disclosures [Line Items]                              
Public Utilities, Requested Rate Increase (Decrease), Amount           $ 17,400,000                  
Public Utilities, Requested Rate Increase (Decrease), Percentage           2.40%                  
Public Utilities, Requested Rate Base, Amount           $ 1,188,000,000                  
Public utilities, Requested Increase Related To Rate Base Investments           11,000,000                  
Public Utilities, Requested Increase Related to Generation and Transmission Expenses [1]           6,800,000                  
Public Utilities, Requested Increase Related to Fuel and Purchased Power Expenses           11,000,000                  
Public Utilities, Total Requested Rate Increase Excluding Refunds           28,800,000                  
Public Utilities, Requested Decrease Related to Fuel Refunds [2]           (9,500,000)                  
Public Utilities, Requested Decrease Related to Settlement Refund           (1,900,000)                  
NSP-Wisconsin | PSCW Proceeding - Wisconsin 2017 Electric and Gas Rate Case - Gas Rates 2017                              
Public Utilities, General Disclosures [Line Items]                              
Public Utilities, Requested Rate Increase (Decrease), Amount           $ 4,800,000                  
Public Utilities, Requested Rate Increase (Decrease), Percentage           3.90%                  
NSP-Wisconsin | PSCW Proceeding - Wisconsin 2017 Electric and Gas Rate Case                              
Public Utilities, General Disclosures [Line Items]                              
Public Utilities, Requested Return on Equity, Percentage           10.00%                  
Percentage of Excess Earnings to be Refunded Due to Earnings Cap           100.00%                  
NSP-Wisconsin | MPSC Proceeding - Michigan 2017 Natural Gas Rate Case                              
Public Utilities, General Disclosures [Line Items]                              
Public Utilities, Requested Rate Increase (Decrease), Amount       $ 347,000                      
Public Utilities, Requested Rate Increase (Decrease), Percentage       6.50%                      
Public Utilities, Requested Rate Base, Amount       $ 6,400,000                      
Public Utilities, Requested Return on Equity, Percentage       10.20%                      
Public Utilities, Requested Equity Capital Structure, Percentage       52.56%                      
Public Utilities, Requested Rider Revenue, Amount       $ 129,000                      
Public Utilities, Requested Rider Revenue, Percentage       2.40%                      
NSP-Wisconsin | Nuclear Project Prudency Investigation                              
Public Utilities, General Disclosures [Line Items]                              
Loss on Monticello life cycle management/extended power uprate project                   $ 5,000,000          
NSP-Wisconsin | Public Service Commission of Wisconsin (PSCW) | PSCW Proceeding - Wisconsin 2017 Electric and Gas Rate Case - Electric Rates 2017                              
Public Utilities, General Disclosures [Line Items]                              
Public Utilities, Approved Rate Increase (Decrease), Amount     $ 22,500,000                        
Public Utilities, Approved Rate Increase (Decrease), Percentage     3.20%                        
Public Utilities, Approved Increase Related to Rate Base Investments     $ 7,600,000                        
Public Utilities, Approved Increase Related to Generation and Transmission Expenses [1]     6,100,000                        
Public Utilities, Approved Increase Related to Fuel and Purchased Power Expenses     10,700,000                        
Public Utilities, Total Approved Rate Increase, Excluding Refunds     24,400,000                        
Public Utilities, Approved Decrease Related to Fuel Refunds [2]     0                        
Public Utilities, Approved Decrease Related to Settlement Refund     (1,900,000)                        
Public Utilities, Revised Requested Rate Increase         $ 29,900,000                    
Public Utilities, Revised Requested Rate Increase, Percentage         4.20%                    
NSP-Wisconsin | Public Service Commission of Wisconsin (PSCW) | PSCW Proceeding - Wisconsin 2017 Electric and Gas Rate Case - Gas Rates 2017                              
Public Utilities, General Disclosures [Line Items]                              
Public Utilities, Approved Rate Increase (Decrease), Amount     $ 4,800,000                        
Public Utilities, Approved Rate Increase (Decrease), Percentage     3.90%                        
NSP-Minnesota | Nuclear Project Prudency Investigation                              
Public Utilities, General Disclosures [Line Items]                              
Nuclear Project Expenditures, Amount                           $ 665,000,000  
Total Capitalized Nuclear Project Costs                           $ 748,000,000  
Initial Estimated Nuclear Project Expenditures                             $ 320,000,000
Loss on Monticello life cycle management/extended power uprate project                   129,000,000          
NSP-Minnesota | FERC Proceeding, MISO ROE Complaint                              
Public Utilities, General Disclosures [Line Items]                              
Public Utilities, Base Return on Equity Charged to Customers Through Transmission Formula Rates               12.38% 12.38%            
Public Utilities, ROE Applicable to Transmission Formula Rates in the MISO Region, Recommended by Third Parties               8.67% 9.15%            
Public Utilities, Maximum Equity Capital Structure Percentage Allowed Per the Complaint                 50.00%            
NSP-Minnesota | Minnesota Public Utilities Commission | Nuclear Project Prudency Investigation                              
Public Utilities, General Disclosures [Line Items]                              
Public Utilities, Amount Of Recoverable Investment, With Return             $ 415,000,000                
Public Utilities, Amount Of Recoverable Investment, Without A Return             $ 333,000,000                
NSP-Minnesota | Federal Energy Regulatory Commission (FERC) | FERC Proceeding, MISO ROE Complaint                              
Public Utilities, General Disclosures [Line Items]                              
Public Utilities, ROE Applicable To Transmission Formula Rates In The MISO Region, Approved 10.32%                            
Public Utilities, Length of Refund Period, In Months 15 months                            
Public Utilities, ROE Applicable To Transmission Formula Rates In The MISO Region, with RTO Adder, Approved                     10.82%        
Public Utilities, ROE Basis Point Adder, Approved                     50        
NSP-Minnesota | MPUC, NDPSC, SDPUC, and DOC | FERC Proceeding, MISO ROE Complaint                              
Public Utilities, General Disclosures [Line Items]                              
Public Utilities, ROE Applicable to Transmission Formula Rates in the MISO Region, Recommended by Third Parties                     8.81%        
NSP-Minnesota | FERC Staff | FERC Proceeding, MISO ROE Complaint                              
Public Utilities, General Disclosures [Line Items]                              
Public Utilities, ROE Applicable to Transmission Formula Rates in the MISO Region, Recommended by Third Parties                     8.78%        
NSP-Minnesota | MISO TOs | FERC Proceeding, MISO ROE Complaint                              
Public Utilities, General Disclosures [Line Items]                              
Public Utilities, ROE Applicable to Transmission Formula Rates in the MISO Region, Recommended by Third Parties                     10.92%        
NSP-Minnesota | Administrative Law Judge | FERC Proceeding, MISO ROE Complaint                              
Public Utilities, General Disclosures [Line Items]                              
Public Utilities, ROE Applicable to Transmission Formula Rates in the MISO Region, Recommended by Third Parties   9.70%                          
Xcel Energy Inc. | Nuclear Project Prudency Investigation                              
Public Utilities, General Disclosures [Line Items]                              
Loss on Monticello life cycle management/extended power uprate project                   $ 129,000,000          
Minimum | NSP-Minnesota | Nuclear Project Prudency Investigation                              
Public Utilities, General Disclosures [Line Items]                              
Public Utilities, Facility Generating Capacity, In MW | MW                       600      
Maximum | NSP-Minnesota | Nuclear Project Prudency Investigation                              
Public Utilities, General Disclosures [Line Items]                              
Public Utilities, Facility Generating Capacity, In MW | MW                       671      
[1] Includes Interchange Agreement billings. For financial reporting purposes, these expenses are included in O&M.
[2] In July 2016, the PSCW required NSP-Wisconsin to return the 2015 fuel refund directly to customers, rather than using it to offset the proposed 2017 rate increase, as originally proposed by NSP-Wisconsin. This decision, when combined with the increase in forecasted fuel and purchased power expense, effectively increased NSP-Wisconsin’s requested electric rate increase to $29.9 million, or 4.2 percent.
v3.6.0.2
Commitments and Contingencies, Fuel Contracts (Details)
$ in Millions
 12 Months Ended
Dec. 31, 2016
USD ($)
Unrecorded Unconditional Purchase Obligation [Line Items]  
Minimum annual tolerance band percentage for future rate recovery or refund of fuel costs (in hundredths) 2.00%
Coal  
Fuel Contracts [Abstract]  
2017 $ 6.9
2018 2.5
2019 0.8
2020 0.8
2021 0.8
Thereafter 1.7
Total 13.5 [1]
Natural Gas Supply  
Fuel Contracts [Abstract]  
2017 10.9
2018 0.3
2019 0.3
2020 0.3
2021 0.3
Thereafter 0.4
Total 12.5 [1]
Natural Gas Storage and Transportation  
Fuel Contracts [Abstract]  
2017 13.2
2018 12.3
2019 11.4
2020 9.1
2021 8.4
Thereafter 36.1
Total $ 90.5 [1]
Minimum  
Unrecorded Unconditional Purchase Obligation [Line Items]  
Fuel Contract Expiration Date 2017
Maximum  
Unrecorded Unconditional Purchase Obligation [Line Items]  
Fuel Contract Expiration Date 2029
[1] Excludes additional amounts allocated to NSP-Wisconsin through intercompany charges.
v3.6.0.2
Commitments and Contingencies, Leases (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Operating Leases [Abstract]      
Total expenses under operating lease obligations $ 1.2 $ 1.1 $ 1.3
Office Space and Other Equipment      
Operating Leases, Future Minimum Payments Due [Abstract]      
2017 1.0    
2018 1.0    
2019 1.0    
2020 0.9    
2021 0.8    
Thereafter 5.3    
Total $ 10.0    
v3.6.0.2
Commitments and Contingencies, Variable Interest Entities (Details) - Low-Income Housing Limited Partnerships - USD ($)
$ in Thousands
Dec. 31, 2016
Dec. 31, 2015
Amount Reflected in Consolidated Balance Sheets [Abstract]    
Current assets $ 375 $ 377
Property, plant and equipment, net 2,025 2,199
Other noncurrent assets 125 127
Total assets 2,525 2,703
Current liabilities 1,269 1,246
Mortgages and other long-term debt payable 486 537
Other noncurrent liabilities 54 51
Total liabilities $ 1,809 $ 1,834
v3.6.0.2
Commitments and Contingencies, Joint Operating System (Details)
$ in Millions
 12 Months Ended
Dec. 31, 2016
USD ($)
Plant
Reactor
Counterparty
Jan. 01, 2017
USD ($)
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 $ 375.0 $ 450.0
Nuclear insurance coverage exposure funded by the Secondary Financial Protection Program 13,000.0  
Maximum assessments per reactor per accident $ 127.3  
Number of owned and licensed reactors | Reactor 3  
Maximum funding requirement per reactor for any one year $ 19.0  
Term for maximum installment payment assessment per reactor (in years) 1 year  
Insurance coverage limits for NSP-Minnesota's nuclear plant sites $ 2,300.0  
Number of nuclear plant sites operated by NSP-Minnesota | Plant 2  
Maximum assessments for business interruption insurance each calendar year $ 19.8  
Maximum assessment for property damage insurance NSP-Minnesota is subject to each calendar year 43.0  
Maximum | NSP-Minnesota | Nuclear Insurance    
Joint Operating System [Abstract]    
Maximum possible loss contingency $ 13,400.0  
v3.6.0.2
Commitments and Contingencies, Guarantees (Details) - Payment or Performance Guarantee - Customer Loans for Farm Rewiring Program
 12 Months Ended
Dec. 31, 2016
USD ($)
Guarantee [Abstract]  
Assets held as collateral $ 0
Guarantees issued and outstanding 1,000,000
Current exposure under these guarantees $ 100,000
Guarantee Expiration Date (year) 2020
Guarantee Obligations Claims made $ 0
v3.6.0.2
Commitments and Contingencies, Environmental Contingencies - Site Contingencies (Details)
$ in Millions
 1 Months Ended 12 Months Ended
Feb. 28, 2017
Dec. 31, 2016
USD ($)
Site
Dec. 31, 2016
USD ($)
Site
Dec. 31, 2015
USD ($)
Ashland MGP Site        
Manufactured Gas Plant (MGP) Site [Abstract]        
Number of Properties Not Owned Included in Superfund Site | Site   2 2  
Accrual for Environmental Loss Contingencies, Gross   $ 64.3 $ 64.3 $ 94.4
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%  
Ashland MGP Site - Phase I Project Area        
Manufactured Gas Plant (MGP) Site [Abstract]        
Accrual for Environmental Loss Contingencies, Gross   72.4 $ 72.4  
Estimated Amount Spent on Cleanup   $ 56.7 $ 56.7  
Other MGP Sites        
Manufactured Gas Plant (MGP) Site [Abstract]        
Number of Identified MGP sites Under Current Investigation and/or Remediation | Site   1 1  
Liability for Estimated Cost of Remediating Site   $ 0.1 $ 0.1 $ 0.2
PSCW Proceeding - Electric and Gas Rate Case 2016 - Gas Rates 2016 | Ashland MGP Site        
Manufactured Gas Plant (MGP) Site [Abstract]        
Public Utilities, Approved Annual Recovery, For 2016, Collected Through Base Rates     $ 7.6  
PSCW Proceeding - Gas Rate Case 2017 - Gas Rates 2017 | Ashland MGP Site        
Manufactured Gas Plant (MGP) Site [Abstract]        
Public Utilities, Approved Annual Recovery Collected Through Base Rates   $ 12.4    
Subsequent Event | Ashland MGP Site Phase II Project Area        
Manufactured Gas Plant (MGP) Site [Abstract]        
Length of Public Comment Period that Lapsed 30 days      
v3.6.0.2
Commitments and Contingencies Commitments and Contingencies, Environmental Contingencies - Unrecorded Unconditional Purchase Obligation (Details)
$ in Millions
Dec. 31, 2016
USD ($)
Plant
Dec. 31, 2015
Period
Federal Clean Water Act Section 316(b)    
Environmental Requirements [Abstract]    
Minimum Number of Plants Which Could Be Required to Make Improvements to Reduce Entrainment | Plant 2  
National Ambient Air Quality Standards for Ozone    
Environmental Requirements [Abstract]    
Number of Hours Measured for Standard | Period   8
Former Level of Air Quality Concentrations (in parts per billion)   75
Revised Level of Air Quality Concentrations (in parts per billion)   70
Capital Commitments | Federal Clean Water Act Section 316(b)    
Environmental Requirements [Abstract]    
Liability for Estimated Cost to Comply with Entrainment Regulation | $ $ 4  
v3.6.0.2
Commitments and Contingencies, Asset Retirement Obligations (Details) - USD ($)
 12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Asset Retirement Obligations [Line Items]    
Liabilities Settled $ 29,000  
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]    
Beginning balance 9,687,000 [1],[2] $ 9,090,000 [3]
Liabilities Incurred 0 0
Accretion 342,000 319,000
Cash Flow Revisions 1,392,000 278,000
Ending balance 11,392,000 [3],[4] 9,687,000 [1],[2]
Electric Plant Steam Production Asbestos    
Asset Retirement Obligations [Line Items]    
Liabilities Settled 0 0
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]    
Beginning balance 2,145,000 [1] 2,049,000
Liabilities Incurred 0 0
Accretion 49,000 45,000
Cash Flow Revisions 0 51,000
Ending balance 2,194,000 [4] 2,145,000 [1]
Electric Plant Steam Production Ash Containment    
Asset Retirement Obligations [Line Items]    
Liabilities Settled 0 0
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]    
Beginning balance 617,000 [1] 374,000
Liabilities Incurred 0 0
Accretion 18,000 14,000
Cash Flow Revisions (183,000) 229,000
Ending balance 452,000 [4] 617,000 [1]
Electric Plant Electric Distribution    
Asset Retirement Obligations [Line Items]    
Liabilities Settled 0 0
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]    
Beginning balance 72,000 [1] 37,000
Liabilities Incurred 0 0
Accretion 3,000 1,000
Cash Flow Revisions (43,000) 34,000
Ending balance 32,000 [4] 72,000 [1]
Electric Plant Other    
Asset Retirement Obligations [Line Items]    
Liabilities Settled 29,000 0
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]    
Beginning balance 391,000 [1] 412,000
Liabilities Incurred 0 0
Accretion 14,000 15,000
Cash Flow Revisions 0 (36,000)
Ending balance 376,000 [4] 391,000 [1]
Natural Gas Plant Gas Distribution    
Asset Retirement Obligations [Line Items]    
Liabilities Settled 0 0
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]    
Beginning balance 6,367,000 [1] 6,127,000
Liabilities Incurred 0 0
Accretion 256,000 240,000
Cash Flow Revisions 1,670,000 0
Ending balance 8,293,000 [4] 6,367,000 [1]
Common and Other Property Common Miscellaneous    
Asset Retirement Obligations [Line Items]    
Liabilities Settled 0 0
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]    
Beginning balance 95,000 [1] 91,000
Liabilities Incurred 0 0
Accretion 2,000 4,000
Cash Flow Revisions (52,000) 0
Ending balance $ 45,000 [4] $ 95,000 [1]
[1] (a) There were no ARO liabilities recognized or settled during the year ended Dec. 31, 2015.
[2] (b) Included in other long-term liabilities balance in the consolidated balance sheet.
[3] (b) Included in other long-term liabilities balance in the consolidated balance sheet.
[4] (a) There were no ARO liabilities recognized during the year ended Dec. 31, 2016.
v3.6.0.2
Commitments and Contingencies Commitments and Contingencies, Removal Costs (Details) - USD ($)
$ in Millions
Dec. 31, 2016
Dec. 31, 2015
Plant Removal Costs    
Regulatory Liabilities [Line Items]    
Regulatory Liabilities $ 140 $ 132
v3.6.0.2
Commitments and Contingencies, Legal Contingencies (Details) - Gas Trading Litigation
 12 Months Ended
Dec. 31, 2016
Dec. 31, 2009
Loss Contingencies [Line Items]    
Loss Contingency, Pending Claims, Number 1 13
Loss Contingency, Claims Settled, Number 5  
Loss Contingency, Claims Dismissed, Number 7  
Loss Contingency, Subset of Cases within Multi-District Litigation, Number 2  
NSP-Wisconsin    
Loss Contingencies [Line Items]    
Loss Contingency, Pending Claims, Number   2
v3.6.0.2
Regulatory Assets and Liabilities, Regulatory Assets (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Regulatory Assets [Line Items]    
Regulatory Asset, Current $ 18,162 $ 16,146
Regulatory Asset, Noncurrent 286,188 289,196
Past expenditures not currently earning a return $ 0 1,000
Environmental Remediation Costs    
Regulatory Assets [Line Items]    
Regulatory asset, remaining amortization period Various  
Regulatory Asset, Current $ 10,669 6,702
Regulatory Asset, Noncurrent $ 148,880 160,699
Pension and Retiree Medical Obligations    
Regulatory Assets [Line Items]    
Regulatory asset, remaining amortization period Various  
Regulatory Asset, Current [1] $ 5,989 6,415
Regulatory Asset, Noncurrent [1] $ 93,160 86,778
Recoverable Deferred Taxes on AFUDC Recorded in Plant    
Regulatory Assets [Line Items]    
Regulatory asset, remaining amortization period Plant lives  
Regulatory Asset, Current $ 0 0
Regulatory Asset, Noncurrent $ 22,345 20,586
State Commission Adjustments    
Regulatory Assets [Line Items]    
Regulatory asset, remaining amortization period Plant lives  
Regulatory Asset, Current $ 703 724
Regulatory Asset, Noncurrent $ 14,008 12,945
Losses on Reacquired Debt    
Regulatory Assets [Line Items]    
Regulatory asset, remaining amortization period Term of related debt  
Regulatory Asset, Current $ 801 803
Regulatory Asset, Noncurrent $ 3,333 4,134
Deferred Income Tax Adjustment    
Regulatory Assets [Line Items]    
Regulatory asset, remaining amortization period Typically plant lives  
Regulatory Asset, Current $ 0 0
Regulatory Asset, Noncurrent $ 2,078 2,250
Other Regulatory Assets    
Regulatory Assets [Line Items]    
Regulatory asset, remaining amortization period Various  
Regulatory Asset, Current $ 0 1,502
Regulatory Asset, Noncurrent $ 2,384 $ 1,804
[1] (a) Includes the non-qualified pension plan.
v3.6.0.2
Regulatory Assets and Liabilities, Regulatory Liabilities (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Regulatory Liabilities [Line Items]    
Regulatory Liability, Current $ 17,428 $ 11,781
Regulatory Liability, Noncurrent $ 148,189 141,289
Plant Removal Costs    
Regulatory Liabilities [Line Items]    
Regulatory liability, remaining amortization period Plant lives  
Regulatory Liability, Current $ 0 0
Regulatory Liability, Noncurrent $ 139,735 132,311
Investment Tax Credit Deferrals    
Regulatory Liabilities [Line Items]    
Regulatory liability, remaining amortization period Various  
Regulatory Liability, Current $ 0 0
Regulatory Liability, Noncurrent $ 8,342 8,869
Deferred Electric Production And Natural Gas Costs    
Regulatory Liabilities [Line Items]    
Regulatory liability, remaining amortization period Less than one year  
Regulatory Liability, Current $ 11,377 9,386
Regulatory Liability, Noncurrent $ 0 0
DOE Settlement    
Regulatory Liabilities [Line Items]    
Regulatory liability, remaining amortization period Less than one year  
Regulatory Liability, Current $ 4,822 1,996
Regulatory Liability, Noncurrent $ 0 0
Conservation Programs    
Regulatory Liabilities [Line Items]    
Regulatory liability, remaining amortization period Less than one year  
Regulatory Liability, Current $ 1,122 339
Regulatory Liability, Noncurrent $ 0 0
Other Regulatory Liabilities    
Regulatory Liabilities [Line Items]    
Regulatory liability, remaining amortization period Various  
Regulatory Liability, Current $ 107 60
Regulatory Liability, Noncurrent $ 112 $ 109
v3.6.0.2
Other Comprehensive Income (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Accumulated Other Comprehensive Income (Loss) [Line Items]      
Accumulated other comprehensive loss at beginning of period $ 790,385    
Accumulated other comprehensive loss at end of period 811,850 $ 790,385  
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]      
Total, pre-tax (112,037) (118,874) $ (113,045)
Income tax expense (benefit) 42,902 44,238 42,403
Gains and Losses on Cash Flow Hedges      
Accumulated Other Comprehensive Income (Loss) [Line Items]      
Accumulated other comprehensive loss at beginning of period (209) (285)  
Accumulated other comprehensive loss at end of period (133) (209) $ (285)
AOCI Attributable to Parent, Net of Tax [Roll Forward]      
(Gains) losses reclassified from net accumulated other comprehensive loss 76 76  
Net current period other comprehensive income (loss) 76 76  
Gains and Losses on Cash Flow Hedges | Amounts Reclassified from Accumulated Other Comprehensive Loss      
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]      
Total, pre-tax 127 127  
Income tax expense (benefit) (51) (51)  
Total, net of tax 76 76  
Gains and Losses on Cash Flow Hedges | Interest Rate Derivatives | Amounts Reclassified from Accumulated Other Comprehensive Loss      
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]      
Interest charges [1] $ 127 $ 127  
[1] Included in interest charges.
v3.6.0.2
Segments and Related Information (Details) - USD ($)
$ in Thousands
 3 Months Ended 12 Months Ended
Dec. 31, 2016
Sep. 30, 2016
Jun. 30, 2016
Mar. 31, 2016
Dec. 31, 2015
Sep. 30, 2015
Jun. 30, 2015
Mar. 31, 2015
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Segment Reporting Information [Line Items]                      
Intercompany Revenue                 $ 170,000 $ 163,000 $ 145,000
Operating revenues $ 237,066 $ 246,144 $ 219,173 $ 254,850 $ 229,607 $ 236,161 $ 216,813 $ 273,960 957,233 956,541 1,000,462
Depreciation and amortization                 98,294 91,245 79,654
Total interest charges and financing costs                 32,629 29,221 25,913
Income tax expense (benefit)                 42,902 44,238 42,403
Net income (loss) $ 14,658 $ 24,221 $ 12,625 $ 17,631 $ 13,625 $ 26,232 $ 12,512 $ 22,267 69,135 74,636 70,642
Regulated Electric                      
Segment Reporting Information [Line Items]                      
Operating revenues                 850,343 835,417 830,245
Depreciation and amortization                 81,299 77,036 65,978
Total interest charges and financing costs                 29,749 26,494 23,448
Income tax expense (benefit)                 40,547 40,654 39,621
Net income (loss)                 65,002 69,398 59,060
Regulated Natural Gas                      
Segment Reporting Information [Line Items]                      
Operating revenues                 106,644 120,645 174,514
Depreciation and amortization                 16,794 14,034 13,501
Total interest charges and financing costs                 2,855 2,637 2,358
Income tax expense (benefit)                 2,445 2,501 5,993
Net income (loss)                 4,503 4,862 8,714
All Other                      
Segment Reporting Information [Line Items]                      
Operating revenues                 1,130 1,396 1,085
Depreciation and amortization                 201 175 175
Total interest charges and financing costs                 25 90 107
Income tax expense (benefit)                 (90) 1,083 (3,211)
Net income (loss)                 (370) 376 2,868
Operating Segments                      
Segment Reporting Information [Line Items]                      
Operating revenues [1]                 957,233 956,541 1,000,462
Operating Segments | Regulated Electric                      
Segment Reporting Information [Line Items]                      
Operating revenues [1]                 849,946 834,998 829,748
Operating Segments | Regulated Natural Gas                      
Segment Reporting Information [Line Items]                      
Operating revenues [1]                 106,157 120,147 169,629
Operating Segments | All Other                      
Segment Reporting Information [Line Items]                      
Operating revenues [1]                 1,130 1,396 1,085
Intersegment Eliminations                      
Segment Reporting Information [Line Items]                      
Operating revenues                 (884) (917) (5,382)
Depreciation and amortization                 0 0 0
Total interest charges and financing costs                 0 0 0
Income tax expense (benefit)                 0 0 0
Net income (loss)                 0 0 0
Intersegment Eliminations | Regulated Electric                      
Segment Reporting Information [Line Items]                      
Operating revenues                 397 419 497
Intersegment Eliminations | Regulated Natural Gas                      
Segment Reporting Information [Line Items]                      
Operating revenues                 487 498 4,885
Intersegment Eliminations | All Other                      
Segment Reporting Information [Line Items]                      
Operating revenues                 $ 0 $ 0 $ 0
[1] Operating revenues include $170 million, $163 million and $145 million of intercompany revenue for the years ended Dec. 31, 2016, 2015 and 2014 respectively. See Note 15 for further discussion of related party transactions by operating segment.
v3.6.0.2
Related Party Transactions (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Related Party Transaction [Line Items]      
Deferred Purchased Power Costs     $ 5,200
Transmission costs deferred as regulatory liability     11,000
Operating revenues      
Electric $ 170,483 $ 163,255 145,102
Operating expenses      
Purchased power 413,615 419,028 430,666
Transmission expense 61,920 54,070 43,876
Natural gas purchased for resale 41 45 90
Other operating expenses - paid to Xcel Energy Services Inc. 106,454 93,890 84,224
Interest expense 4 2 $ 30
Accounts Receivable and Payable with Affiliates [Abstract]      
Accounts receivable 333 71  
Accounts payable 29,037 24,538  
NSP-Minnesota      
Accounts Receivable and Payable with Affiliates [Abstract]      
Accounts receivable 0 0  
Accounts payable 18,567 18,268  
PSCo      
Accounts Receivable and Payable with Affiliates [Abstract]      
Accounts receivable 0 0  
Accounts payable 974 71  
SPS      
Accounts Receivable and Payable with Affiliates [Abstract]      
Accounts receivable 333 71  
Accounts payable 0 0  
Other subsidiaries of Xcel Energy Inc.      
Accounts Receivable and Payable with Affiliates [Abstract]      
Accounts receivable 0 0  
Accounts payable $ 9,496 $ 6,199  
v3.6.0.2
Summarized Quarterly Financial Data (Unaudited) (Details) - USD ($)
$ in Thousands
 3 Months Ended 12 Months Ended
Dec. 31, 2016
Sep. 30, 2016
Jun. 30, 2016
Mar. 31, 2016
Dec. 31, 2015
Sep. 30, 2015
Jun. 30, 2015
Mar. 31, 2015
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Quarterly Financial Information Disclosure [Abstract]                      
Operating revenues $ 237,066 $ 246,144 $ 219,173 $ 254,850 $ 229,607 $ 236,161 $ 216,813 $ 273,960 $ 957,233 $ 956,541 $ 1,000,462
Operating income 30,360 46,342 27,778 35,448 27,809 47,532 25,069 39,549 139,928 139,959 131,628
Net income $ 14,658 $ 24,221 $ 12,625 $ 17,631 $ 13,625 $ 26,232 $ 12,512 $ 22,267 $ 69,135 $ 74,636 $ 70,642
v3.6.0.2
Schedule II, Valuation and Qualifying Accounts (Details) - Allowance for Bad Debts - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2016
Dec. 31, 2015
Dec. 31, 2014
Movement in Valuation Allowances and Reserves [Roll Forward]      
Balance at Jan. 1 $ 5,128 $ 5,821 $ 4,911
Charged to costs and expenses 3,730 3,947 4,431
Charged to other accounts [1] 1,008 1,161 1,269
Deductions from reserves [2] 5,001 5,801 4,790
Balance at Dec. 31 $ 4,865 $ 5,128 $ 5,821
[1] Recovery of amounts previously written off.
[2] Deductions relate primarily to bad debt write-offs.