Northern States Power 10-K 24 Feb 14 2013 Q4 Annual report Financial data

Document_and_Entity_Informatio

Document and Entity Information (USD $)	12 Months Ended
	Dec. 31, 2013	Feb. 24, 2014	Jun. 30, 2013
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	31-Dec-13	'	'
Document Fiscal Year Focus	'2013	'	'
Document Fiscal Period Focus	'Q4	'	'
Amendment Flag	'false	'	'
Entity Common Stock, Shares Outstanding	'	933,000	'
Entity Well-known Seasoned Issuer	'No	'	'
Entity Voluntary Filers	'No	'	'
Entity Current Reporting Status	'Yes	'	'
Entity Public Float	'	'	$0

CONSOLIDATED_STATEMENTS_OF_INC

CONSOLIDATED STATEMENTS OF INCOME (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Operating revenues	'	'	'
Electric	$789,168	$757,565	$755,136
Natural gas	132,867	103,100	119,447
Other	1,003	1,177	1,207
Total operating revenues	923,038	861,842	875,790
Operating expenses	'	'	'
Electric fuel and purchased power, non-affiliates	18,129	19,440	20,957
Purchased power, affiliates	416,173	405,016	399,649
Cost of natural gas sold and transported	81,572	61,370	78,208
Operating and maintenance expenses	175,522	167,503	164,323
Conservation program expenses	12,333	14,442	12,883
Depreciation and amortization	76,897	69,234	68,574
Taxes (other than income taxes)	25,231	24,971	23,688
Total operating expenses	805,857	761,976	768,282
Operating income	117,181	99,866	107,508
Other income, net	253	476	98
Allowance for funds used during construction — equity	4,259	2,104	1,007
Interest charges and financing costs	'	'	'
Interest charges — includes other financing costs of $1,538, $1,574 and $1,713, respectively	27,797	24,799	24,168
Allowance for funds used during construction — debt	-1,981	-1,862	-175
Total interest charges and financing costs	25,816	22,937	23,993
Income before income taxes	95,877	79,509	84,620
Income taxes	36,409	29,558	33,614
Net income	$59,468	$49,951	$51,006

CONSOLIDATED_STATEMENTS_OF_INC1

CONSOLIDATED STATEMENTS OF INCOME (Parenthetical) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Interest charges and financing costs	'	'	'
Other financing costs	$1,538	$1,574	$1,713

CONSOLIDATED_STATEMENTS_OF_COM

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Comprehensive income:	'	'	'
Net income	$59,468	$49,951	$51,006
Derivative instruments:	'	'	'
Reclassification of losses to net income, net of tax of $51, $51 and $51, respectively.	76	77	76
Other comprehensive income	76	77	76
Comprehensive income	$59,544	$50,028	$51,082

CONSOLIDATED_STATEMENTS_OF_COM1

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Derivative instruments:	'	'	'
Reclassification of losses to net income, net of tax	($51)	($51)	($51)

CONSOLIDATED_STATEMENTS_OF_CAS

CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Operating activities	'	'	'
Net income	$59,468	$49,951	$51,006
Adjustments to reconcile net income to cash provided by operating activities:	'	'	'
Depreciation and amortization	78,048	70,372	69,900
Deferred income taxes	25,789	27,107	35,610
Amortization of investment tax credits	-664	-626	-611
Allowance for equity funds used during construction	-4,259	-2,104	-1,007
Provision for bad debts	3,988	3,329	3,842
Net derivative (gains) losses	-279	127	127
Changes in operating assets and liabilities:	'	'	'
Accounts receivable	-12,702	-15,953	-4,013
Accrued unbilled revenues	-2,496	-470	2,911
Inventories	-1,879	6,018	913
Other current assets	-3,749	-3,172	-1,180
Accounts payable	-1,811	5,828	-16,614
Net regulatory assets and liabilities	-2,062	3,623	10,008
Other current liabilities	7,589	3,681	-2,260
Pension and other employee benefit obligations	-8,759	-10,857	-7,214
Change in other noncurrent assets	232	14	564
Change in other noncurrent liabilities	1,119	-595	-2,682
Net cash provided by operating activities	137,573	136,273	139,300
Investing activities	'	'	'
Utility capital/construction expenditures	-201,278	-152,759	-140,982
Allowance for equity funds used during construction	4,259	2,104	1,007
Other, net	-421	916	-112
Net cash used in investing activities	-197,440	-149,739	-140,087
Financing activities	'	'	'
Proceeds from (repayments of) short-term borrowings, net	29,000	-27,000	66,000
Proceeds from notes payable to affiliates	0	50	111,300
Repayments Of Notes Payable To Affiliates	-80	0	-148,350
Proceeds from Issuance of Long-term Debt	0	97,916	0
Repayments of long-term debt	-160	-97	-96
Capital contributions from parent	58,977	2,796	0
Dividends paid to parent	-30,980	-57,311	-32,941
Net cash provided by (used in) financing activities	56,757	16,354	-4,087
Net change in cash and cash equivalents	-3,110	2,888	-4,874
Cash and cash equivalents at beginning of period	4,459	1,571	6,445
Cash and cash equivalents at end of period	1,349	4,459	1,571
Supplemental disclosure of cash flow information:	'	'	'
Cash paid for interest (net of amounts capitalized)	-24,376	-21,035	-22,616
Cash (paid) received for income taxes, net	-9,842	-5,841	1,116
Supplemental disclosure of non-cash investing transactions:	'	'	'
Property, plant and equipment additions in accounts payable	$27,222	$10,618	$9,427

CONSOLIDATED_BALANCE_SHEETS

CONSOLIDATED BALANCE SHEETS (USD $)	Dec. 31, 2013		Dec. 31, 2012
In Thousands, unless otherwise specified
Current assets	'		'
Cash and cash equivalents	$1,349		$4,459
Accounts receivable, net	59,269	[1]	50,706	[1]
Accrued unbilled revenues	51,634		49,138
Inventories	21,475		19,685
Regulatory assets	14,866		12,048
Prepaid taxes	27,518		24,688
Deferred income taxes	14,953		0
Prepayments and other	5,056		4,394
Total current assets	196,120		165,118
Property, plant and equipment, net	1,442,779		1,298,236
Other assets	'		'
Regulatory assets	233,193		240,459
Other investments	3,650		3,232
Other	3,651		4,040
Total other assets	240,494		247,731
Total assets	1,879,393		1,711,085
Current liabilities	'		'
Current portion of long-term debt	107		1,246
Short-term debt	68,000		39,000
Notes payable to affiliates	470		550
Accounts payable	52,086		30,723
Accounts payable to affiliates	24,986		31,556
Dividends payable to parent	8,032		7,667
Regulatory liabilities	9,717		6,086
Taxes accrued	5,638		839
Environmental liabilities	28,785		23,427
Accrued interest	7,507		7,304
Other	9,376		10,955
Total current liabilities	214,704		159,353
Deferred credits and other liabilities	'		'
Deferred income taxes	305,139		261,800
Deferred investment tax credits	9,698		8,911
Regulatory liabilities	126,424		123,746
Environmental liabilities	79,703		84,655
Customer advances	16,008		15,631
Pension and employee benefit obligations	45,708		63,643
Other	9,237		8,923
Total deferred credits and other liabilities	591,917		567,309
Commitments and contingencies	'		'
Capitalization	'		'
Long-term debt	468,490		467,317
Common stock — 1,000,000 shares authorized of $100 par value; 933,000 shares outstanding at Dec. 31, 2013 and 2012, respectively	93,300		93,300
Additional paid in capital	248,844		189,867
Retained earnings	262,499		234,376
Accumulated other comprehensive loss	-361		-437
Total common stockholder’s equity	604,282		517,106
Total liabilities and equity	$1,879,393		$1,711,085
[1]	Accounts receivable, net includes $1,595 and $586 due from affiliates as of Dec. 31, 2013 and 2012, respectively.

CONSOLIDATED_BALANCE_SHEETS_Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $)	Dec. 31, 2013	Dec. 31, 2012
Capitalization	'	'
Common stock, shares authorized (in shares)	1,000,000	1,000,000
Common stock, par value (in dollars per share)	$100	$100
Common stock, shares outstanding (in shares)	933,000	933,000

CONSOLIDATED_STATEMENTS_OF_COM2

CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY (USD $)	Total	Common stock	Additional Paid In Capital	Retained Earnings	Accumulated Other Comprehensive Loss
In Thousands, except Share data, unless otherwise specified
Beginning Balance at Dec. 31, 2010	$502,678	$93,300	$187,071	$222,897	($590)
Balance (in shares) at Dec. 31, 2010	'	933,000	'	'	'
Comprehensive income:	'	'	'	'	'
Net income	51,006	'	'	51,006	'
Other comprehensive income	76	'	'	'	76
Common dividends declared to parent	-32,607	'	'	-32,607	'
Contribution of capital by parent	0	'	0	'	'
Ending Balance at Dec. 31, 2011	521,153	93,300	187,071	241,296	-514
Balance (in shares) at Dec. 31, 2011	'	933,000	'	'	'
Comprehensive income:	'	'	'	'	'
Net income	49,951	'	'	49,951	'
Other comprehensive income	77	'	'	'	77
Common dividends declared to parent	-56,871	'	'	-56,871	'
Contribution of capital by parent	2,796	'	2,796	'	'
Ending Balance at Dec. 31, 2012	517,106	93,300	189,867	234,376	-437
Balance (in shares) at Dec. 31, 2012	933,000	933,000	'	'	'
Comprehensive income:	'	'	'	'	'
Net income	59,468	'	'	59,468	'
Other comprehensive income	76	'	'	'	76
Common dividends declared to parent	-31,345	'	'	-31,345	'
Contribution of capital by parent	58,977	'	58,977	'	'
Ending Balance at Dec. 31, 2013	$604,282	$93,300	$248,844	$262,499	($361)
Balance (in shares) at Dec. 31, 2013	933,000	933,000	'	'	'

CONSOLIDATED_STATEMENTS_OF_CAP

CONSOLIDATED STATEMENTS OF CAPITALIZATION (USD $)	Dec. 31, 2013		Dec. 31, 2012
In Thousands, unless otherwise specified
Long-Term Debt	'		'
Unamortized discount	($2,321)		($2,457)
Total long-term debt, including current maturities	468,597		468,563
Less: current maturities	107		1,246
Total long-term debt	468,490		467,317
Common Stockholders' Equity	'		'
Common stock — 1,000,000 shares authorized of $100 par value; 933,000 shares outstanding at Dec. 31, 2013 and 2012, respectively	93,300		93,300
Additional paid in capital	248,844		189,867
Retained earnings	262,499		234,376
Accumulated other comprehensive loss	-361		-437
Total common stockholder’s equity	604,282		517,106
First Mortgage Bonds [Member] | Series Due Oct. 1, 2018 [Member]	'		'
Long-Term Debt	'		'
Long-term debt, gross	150,000		150,000
First Mortgage Bonds [Member] | Series Due Sept. 1, 2038 [Member]	'		'
Long-Term Debt	'		'
Long-term debt, gross	200,000		200,000
First Mortgage Bonds [Member] | Series Due Oct. 1, 2042	'		'
Long-Term Debt	'		'
Long-term debt, gross	100,000		100,000
City of La Crosse Resource Recovery Bond [Member] | Series Due Nov. 1, 2021 [Member]	'		'
Long-Term Debt	'		'
Long-term debt, gross	18,600	[1]	18,600	[1]
Fort McCoy System Acquisition [Member] | Due Oct. 15, 2030 [Member]	'		'
Long-Term Debt	'		'
Long-term debt, gross	558		591
Other	'		'
Long-Term Debt	'		'
Long-term debt, gross	$1,760		$1,829
[1]	Resource recovery financing

CONSOLIDATED_STATEMENTS_OF_CAP1

CONSOLIDATED STATEMENTS OF CAPITALIZATION (Parenthetical)	12 Months Ended
	Dec. 31, 2013
First Mortgage Bonds [Member] | Series Due Oct. 1, 2018 [Member]	'
Long-Term Debt	'
Debt instrument, interest rate stated percentage (in hundredths)	5.25%
Debt instrument, maturity date	1-Oct-18
First Mortgage Bonds [Member] | Series Due Sept. 1, 2038 [Member]	'
Long-Term Debt	'
Debt instrument, interest rate stated percentage (in hundredths)	6.38%
Debt instrument, maturity date	1-Sep-38
First Mortgage Bonds [Member] | Series Due Oct. 1, 2042	'
Long-Term Debt	'
Debt instrument, interest rate stated percentage (in hundredths)	3.70%
Debt instrument, maturity date	1-Oct-42
City of La Crosse Resource Recovery Bond [Member] | Series Due Nov. 1, 2021 [Member]	'
Long-Term Debt	'
Debt instrument, interest rate stated percentage (in hundredths)	6.00%
Debt instrument, maturity date	1-Nov-21
Fort McCoy System Acquisition [Member] | Due Oct. 15, 2030 [Member]	'
Long-Term Debt	'
Debt instrument, interest rate stated percentage (in hundredths)	7.00%
Debt instrument, maturity date	15-Oct-30

Summary_of_Significant_Account

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2013
Accounting Policies [Abstract]	'
Summary of Significant Accounting Policies	'
	Summary of Significant Accounting Policies
	Business and System of Accounts — NSP-Wisconsin is principally 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 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, AROs, 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, 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 sheet.  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 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.
	Requests can be made for recovery of purchased electric energy or fuel for generation prospectively through the rate review process, which normally occurs every two years, or at an interim fuel cost hearing process.  Effective 2011, NSP-Wisconsin began submitting a forward looking fuel cost plan that allows for deferral of fuel cost under-collection or over-collection in excess of a two percent annual tolerance band, for future rate recovery or refund.  Fuel costs are subject to PSCW hearings and approval, and other requirements.
	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 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 that is required to be decommissioned early by a regulator is reclassified as plant to be retired.
	Property, plant and equipment is tested for impairment when it is determined that the carrying value of the assets may not be recoverable. Recently completed property, plant and equipment that is disallowed for cost recovery is expensed in the current period. For investments in property, plant and equipment that are 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 on abandonment 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 and semi-actuarial life studies are performed on a periodic basis and submitted to the state and federal commissions for review.  Upon acceptance by the various commissions, the resulting lives and net salvage rates are used to calculate depreciation.  Depreciation expense, expressed as a percentage of average depreciable property, was approximately 3.5, 3.5 and 3.6 percent for the years ended Dec. 31, 2013, 2012 and 2011, 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 other nonoperating income (for equity capital) and interest charges (for debt capital). AFUDC amounts capitalized are included in NSP-Wisconsin’s rate base for establishing utility service rates.
	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.
	AROs — NSP-Wisconsin records future plant removal obligations as a liability at fair value with a corresponding increase to the carrying values of the related long-lived assets in accordance with the applicable accounting guidance.  This liability will be increased over time by applying the effective interest method of accretion to the liability and the capitalized costs will be depreciated over the useful life of the related long-lived assets.  The recording of the obligation for regulated operations has no income statement impact due to the deferral of the amounts through the establishment of a regulatory asset and recovery in rates.
	NSP-Wisconsin also recovers currently in rates certain future plant removal costs in addition to AROs and related capitalized costs, and a regulatory liability is recognized for such future expenditures.  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. Investment tax credits are deferred and their benefits amortized over the book depreciable lives of the related 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 net asset values.  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.
	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.  The estimates are 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 extend indefinitely 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 are classified as a regulatory liability.
	See Note 11 for further discussion of environmental costs.
	Benefit Plans and Other Postretirement Benefits — NSP-Wisconsin maintains pension and postretirement benefit plans for eligible employees.  Recognizing the cost of providing benefits and measuring the projected benefit obligation of these plans under applicable accounting guidance requires management to make various assumptions and estimates.
	Based on regulatory recovery mechanisms, certain unrecognized actuarial gains and losses and unrecognized prior service costs or credits are recorded as regulatory assets and liabilities, rather than OCI.
	See Note 7 for further discussion of benefit plans and other postretirement benefits.
	Guarantees — NSP-Wisconsin recognizes, upon issuance or modification of a guarantee, a liability for the fair market value of the obligation that has been assumed in issuing the guarantee.  This liability includes consideration of specific triggering events and other conditions which may modify the ongoing obligation to perform under the guarantee.
	The obligation recognized is reduced over the term of the guarantee as NSP-Wisconsin is released from risk under the guarantee.  See Note 11 for specific details of issued guarantees.
	Subsequent Events — Management has evaluated the impact of events occurring after Dec. 31, 2013 up to the date of issuance of these consolidated financial statements.  These statements contain all necessary adjustments and disclosures resulting from that evaluation.

Accounting_Pronouncements

Accounting Pronouncements	12 Months Ended
	Dec. 31, 2013
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]	'
Accounting Pronouncements	'
	Accounting Pronouncements
	Recently Adopted
	Balance Sheet Offsetting — In December 2011, the FASB issued Balance Sheet (Topic 210) — Disclosures about Offsetting Assets and Liabilities (ASU No. 2011-11), which requires disclosures regarding netting arrangements in agreements underlying derivatives, certain financial instruments and related collateral amounts, and the extent to which an entity’s financial statement presentation policies related to netting arrangements impact amounts recorded to the financial statements.  In January 2013, the FASB issued Balance Sheet (Topic 210) – Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities (ASU No. 2013-01) to clarify the specific instruments that should be considered in these disclosures.  These disclosure requirements do not affect the presentation of amounts in the consolidated balance sheets, and were effective for annual reporting periods beginning on or after Jan. 1, 2013, and interim periods within those annual reporting periods.  NSP-Wisconsin implemented the disclosure guidance effective Jan. 1, 2013, and the implementation did not have a material impact on its consolidated financial statements.  See Note 9 for the required disclosures.
	Comprehensive Income Disclosures — In February 2013, the FASB issued Comprehensive Income (Topic 220)  — Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income (ASU No. 2013-02), which requires detailed disclosures regarding changes in components of accumulated OCI and amounts reclassified out of accumulated OCI.  These disclosure requirements do not change how net income or comprehensive income are presented in the consolidated financial statements.  These disclosure requirements were effective for annual reporting periods beginning on or after Dec. 15, 2012, and interim periods within those annual reporting periods.  NSP-Wisconsin implemented the disclosure guidance effective Jan. 1, 2013, and the implementation did not have a material impact on its consolidated financial statements.  See Note 13 for the required disclosures.

Selected_Balance_Sheet_Data

Selected Balance Sheet Data	12 Months Ended
	Dec. 31, 2013
Balance Sheet Related Disclosures [Abstract]	'
Selected Balance Sheet Data	'
	Selected Balance Sheet Data
	(Thousands of Dollars)		Dec. 31, 2013			Dec. 31, 2012
	Accounts receivable, net (a)
	Accounts receivable		$	64,180		$	55,039
	Less allowance for bad debts		(4,911		)	(4,333		)
			$	59,269		$	50,706
	(a)	Accounts receivable, net includes $1,595 and $586 due from affiliates as of Dec. 31, 2013 and 2012, respectively.
	(Thousands of Dollars)		Dec. 31, 2013			Dec. 31, 2012
	Inventories
	Materials and supplies		$	6,437		$	6,172
	Fuel		5,915			6,664
	Natural gas		9,123			6,849
			$	21,475		$	19,685
	(Thousands of Dollars)		Dec. 31, 2013			Dec. 31, 2012
	Property, plant and equipment, net
	Electric plant		$	1,913,354		$	1,795,239
	Natural gas plant		236,047			224,625
	Common and other property		112,886			111,319
	CWIP		127,954			62,629
	Total property, plant and equipment		2,390,241			2,193,812
	Less accumulated depreciation		(947,462		)	(895,576		)
			$	1,442,779		$	1,298,236

Borrowings_and_Other_Financing

Borrowings and Other Financing Instruments	12 Months Ended
	Dec. 31, 2013
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, 2013
	Borrowing limit		$	150
	Amount outstanding at period end		68
	Average amount outstanding		41
	Maximum amount outstanding		71
	Weighted average interest rate, computed on a daily basis		0.3		%
	Weighted average interest rate at period end		0.27
	(Amounts in Millions, Except Interest Rates)		Twelve Months Ended Dec. 31, 2013				Twelve Months Ended Dec. 31, 2012				Twelve Months Ended Dec. 31, 2011
	Borrowing limit		$	150			$	150			$	150
	Amount outstanding at period end		68				39				66
	Average amount outstanding		20				61				24
	Maximum amount outstanding		71				116				70
	Weighted average interest rate, computed on a daily basis		0.31		%		0.39		%		0.37		%
	Weighted average interest rate at period end		0.27				0.4				0.46
	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, 2013 and 2012, there were no letters of credit outstanding.
	Credit Facility — In order to use its commercial paper program to fulfill short-term funding needs, NSP-Wisconsin must have a revolving credit facility in place at least equal to the amount of its commercial paper borrowing limit and cannot issue commercial paper in an aggregate amount exceeding available capacity under this credit facility.  The line of credit provides short-term financing in the form of notes payable to banks, letters of credit and back-up support for commercial paper borrowings.
	NSP-Wisconsin has a five-year credit agreement with a syndicate of banks. The total size of the credit facility is $150 million and the credit facility terminates in July 2017.
	NSP-Wisconsin has the right to request an extension of the revolving termination date for an additional one-year period. All extension requests are subject to majority bank group approval.
	Other features of NSP-Wisconsin’s credit facility include:
	•	The credit facility has a financial covenant requiring that the debt-to-total capitalization ratio be less than or equal to 65 percent. NSP-Wisconsin was in compliance as its debt-to-total capitalization ratio was 47 percent at Dec. 31, 2013. 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.
	•	The interest rates under the line of credit are based on Eurodollar borrowing margins ranging from 87.5 to 175 basis points per year based on the applicable long-term credit ratings.
	•	The commitment fees, also based on applicable long-term credit ratings, are calculated on the unused portion of the lines of credit at a range of 7.5 to 27.5 basis points per year.
	At Dec. 31, 2013, NSP-Wisconsin had the following committed credit facility available (in millions of dollars):
	Credit Facility (a)				Drawn (b)				Available
	$	150			$	68			$	82
	(a)	Credit facility expires in July 2017.
	(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, 2013 and 2012.
	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, 2013				Dec. 31, 2012
	Notes payable to affiliates		$	0.5			$	0.6
	Weighted average interest rate		0.24		%		0.33		%
	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 October 2012, NSP-Wisconsin issued $100.0 million of 3.70 percent first mortgage bonds due Oct. 1, 2042.
	During the next five years, NSP-Wisconsin has long-term debt maturities of $150.0 million due in 2018.
	Deferred Financing Costs — Other assets included deferred financing costs of approximately $3.5 million and $3.6 million, net of amortization, at Dec. 31, 2013 and 2012, 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 under the Federal Power Act, 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 $31.2 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 52.8 percent at Dec. 31, 2013 and $17.1 million in retained earnings was not restricted.

Joint_Ownership_of_Transmissio

Joint Ownership of Transmission Facilities	12 Months Ended
	Dec. 31, 2013
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, 2013:
	(Thousands of Dollars)	Plant in		Accumulated Depreciation		CWIP		Ownership %
		Service
	Electric Transmission:
	CapX2020 Transmission	$	13,337	$	4,659	$	30,199	77.9	%
	La Crosse, Wis. to Madison, Wis.	—		—		5,431		50
	Total NSP-Wisconsin	$	13,337	$	4,659	$	35,630
	NSP-Wisconsin’s share of operating expenses and construction expenditures are included in the applicable utility accounts. Each of the respective owners is responsible for providing its own financing.

Income_Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2013
Income Tax Disclosure [Abstract]	'
Income Taxes	'
	Income Taxes
	Federal Audit — NSP-Wisconsin is a member of the Xcel Energy affiliated group that files a consolidated federal income tax return. The statute of limitations applicable to Xcel Energy’s 2008 federal income tax return expired in September 2012.  The statute of limitations applicable to Xcel Energy’s 2009 federal income tax return expires in June 2015.  In the third quarter of 2012, the IRS commenced an examination of tax years 2010 and 2011, including the 2009 carryback claim. As of Dec. 31, 2013, the IRS had proposed an adjustment to the federal tax loss carryback claims that would result in $10 million of income tax expense for the 2009 through 2011 claims and the anticipated claim for 2013.  NSP-Wisconsin is not expected to accrue any income tax expense related to this adjustment. Xcel Energy is continuing to work through the audit process, but the outcome and timing of a resolution are 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, 2013, NSP-Wisconsin’s earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations is 2009. In the first quarter of 2013, the state of Wisconsin commenced an examination of tax years 2009 through 2011. As of Dec. 31, 2013, no material adjustments had been proposed for these years.  There are currently 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, 2013				Dec. 31, 2012
	Unrecognized tax benefit — Permanent tax positions	$	0.1			$	0.1
	Unrecognized tax benefit — Temporary tax positions	1.4				1.2
	Total unrecognized tax benefit	$	1.5			$	1.3
	A reconciliation of the beginning and ending amount of unrecognized tax benefit is as follows:
	(Millions of Dollars)	2013				2012				2011
	Balance at Jan. 1	$	1.3			$	1.5			$	1.9
	Additions based on tax positions related to the current year	0.7				0.5				0.6
	Reductions based on tax positions related to the current year	—				(0.2		)		(0.1		)
	Additions for tax positions of prior years	0.5				0.3				0.7
	Reductions for tax positions of prior years	—				(0.8		)		(0.3		)
	Settlements with taxing authorities	(1.0		)		—				(1.2		)
	Lapse of applicable statutes of limitations	—				—				(0.1		)
	Balance at Dec. 31	$	1.5			$	1.3			$	1.5
	The unrecognized tax benefit amounts were reduced by the tax benefits associated with NOL and tax credit carryforwards.  The amounts of tax benefits associated with NOL and tax credit carryforwards are as follows:
	(Millions of Dollars)	Dec. 31, 2013				Dec. 31, 2012
	NOL and tax credit carryforwards	$	(0.4	)		$	(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 and state audits progress. As the IRS examination moves closer to completion, the change in the unrecognized tax benefit is not expected to be material.
	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, 2013, 2012 and 2011 were not material. No amounts were accrued for penalties related to unrecognized tax benefits as of Dec. 31, 2013, 2012 or 2011.
	Tangible Property Regulations — In September 2013, the U.S. Treasury issued final regulations addressing the tax consequences associated with the acquisition, production and improvement of tangible property. As NSP-Wisconsin had adopted certain utility-specific guidance previously issued by the IRS, the issuance is not expected to have a material impact on its consolidated financial statements.
	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)	2013			2012
	Federal NOL carryforward	46.8			44.3
	Federal tax credit carryforwards	4.4			8
	State NOL carryforward	6.3			3.4
	The federal carryforward periods expire between 2021 and 2033.  The state carryforward periods expire between 2022 and 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:
		2013			2012			2011
	Federal statutory rate	35	%		35	%		35	%
	Increases (decreases) in tax from:
	State income taxes, net of federal income tax benefit	5			3.4			4.4
	Tax credits recognized	(0.9	)		(0.9	)		(0.9	)
	Regulatory differences — utility plant items	(0.9	)		(0.3	)		0.5
	Change in unrecognized tax benefits	—			0.1			(0.2	)
	Other, net	(0.2	)		(0.1	)		0.9
	Effective income tax rate	38	%		37.2	%		39.7	%
	The components of income tax expense for the years ending Dec. 31 were:
	(Thousands of Dollars)	2013				2012				2011
	Current federal tax expense (benefit)	$	5,902			$	930			$	(1,540	)
	Current state tax expense	4,628				2,216				1,573
	Current change in unrecognized tax expense (benefit)	754				(69		)		(1,418		)
	Deferred federal tax expense	23,794				25,089				30,251
	Deferred state tax expense	2,720				1,890				4,105
	Deferred change in unrecognized tax (benefit) expense	(725		)		128				1,254
	Deferred investment tax credits	(664		)		(626		)		(611		)
	Total income tax expense	$	36,409			$	29,558			$	33,614
	The components of deferred income tax expense for the years ending Dec. 31 were:
	(Thousands of Dollars)	2013				2012				2011
	Deferred tax expense excluding items below	$	27,516			$	27,995			$	34,017
	Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities	(1,676		)		(837		)		1,644
	Tax expense allocated to other comprehensive income	(51		)		(51		)		(51		)
	Deferred tax expense	$	25,789			$	27,107			$	35,610
	The components of the net deferred tax liability (current and noncurrent) at Dec. 31 were as follows:
	(Thousands of Dollars)	2013				2012
	Deferred tax liabilities:
	Difference between book and tax bases of property	$	287,121			$	265,202
	Regulatory assets	57,296				52,898
	Employee benefits	16,953				16,862
Other	10,193				10,535
Total deferred tax liabilities	$	371,563			$	345,497
Deferred tax assets:
Environmental remediation	43,501				43,344
NOL carryforward	17,384				17,588
Regulatory liabilities	6,205				5,927
Deferred investment tax credits	5,976				5,766
Tax credit carryforward	4,440				8,011
Other	3,871				2,191
Total deferred tax assets	$	81,377			$	82,827
Net deferred tax liability	$	290,186			$	262,670

Benefit_Plans_and_Other_Postre

Benefit Plans and Other Postretirement Benefits	12 Months Ended
	Dec. 31, 2013
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 70 percent of employees that receive benefits are represented by several local labor unions under several collective-bargaining agreements. At Dec. 31, 2013, NSP-Wisconsin had 399 bargaining employees covered under a collective-bargaining agreement, which expires at the end of 2016.
	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 net asset values.
	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 equity securities and other funds — Equity securities are valued using quoted prices in active markets. The fair values for commingled funds, private equity investments and real estate investments are measured using net asset values, 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 net asset value with proper notice. Proper notice varies by fund and can range from daily with one or two 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. Unscheduled distributions from real estate investments 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. Based on the plan’s evaluation of its ability to redeem private equity and real estate investments, fair value measurements for private equity and real estate investments have been assigned a Level 3.
	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. Benefits are based on a combination of years of service, the employee’s average pay and 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. The total obligations of the SERP and nonqualified plan as of Dec. 31, 2013 and 2012 were $36.5 million and $39.4 million, respectively, of which $0.6 million and $0.6 million, respectively, was attributable to NSP-Wisconsin. In 2013 and 2012, Xcel Energy recognized net benefit cost for financial reporting for the SERP and nonqualified plans of $6.6 million and $15.6 million, respectively, of which amounts attributable to NSP-Wisconsin were immaterial. Benefits for these unfunded plans are paid out of Xcel Energy’s consolidated operating cash flows.
	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. The pension cost determination assumes a forecasted mix of investment types over the long term. Investment returns in 2013 were below the assumed level of 7.25 percent. Investment returns in 2012 were above the assumed level of 7.50 percent while returns in 2011 were below the assumed level of 8.00 percent. Xcel Energy Inc. and NSP-Wisconsin continually review the pension assumptions. In 2014, NSP-Wisconsin’s expected investment-return assumption is 7.25 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:
			2013			2012
	Domestic and international equity securities		31	%		29	%
	Long-duration fixed income and interest rate swap securities		29			30
	Short-to-intermediate term fixed income securities		16			12
	Alternative investments		22			27
	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, 2013 and 2012:
			Dec. 31, 2013
	(Thousands of Dollars)		Level 1				Level 2				Level 3			Total
	Cash equivalents		$	4,332			$	—			$	—		$	4,332
	Derivatives		—				937				—			937
	Government securities		—				6,711				—			6,711
	Corporate bonds		—				24,955				—			24,955
	Asset-backed securities		—				307				—			307
	Mortgage-backed securities		—				684				—			684
	Common stock		4,533				—				—			4,533
	Private equity investments		—				—				7,502			7,502
	Commingled funds		—				84,364				—			84,364
	Real estate		—				—				2,299			2,299
	Securities lending collateral obligation and other		—				311				—			311
	Total		$	8,865			$	118,269			$	9,801		$	136,935
			Dec. 31, 2012
	(Thousands of Dollars)		Level 1				Level 2				Level 3			Total
	Cash equivalents		$	7,956			$	—			$	—		$	7,956
	Derivatives		—				390				—			390
	Government securities		—				9,406				—			9,406
	Corporate bonds		—				25,046				—			25,046
	Asset-backed securities		—				—				749			749
	Mortgage-backed securities		—				—				2,128			2,128
	Common stock		3,977				—				—			3,977
	Private equity investments		—				—				8,545			8,545
	Commingled funds		—				76,398				—			76,398
	Real estate		—				—				3,472			3,472
	Securities lending collateral obligation and other		—				(1,521		)		—			(1,521		)
	Total		$	11,933			$	109,719			$	14,894		$	136,546
	The following tables present the changes in NSP-Wisconsin’s Level 3 pension plan assets for the years ended Dec. 31, 2013, 2012 and 2011:
	(Thousands of Dollars)		Jan. 1, 2013				Net Realized				Net Unrealized			Purchases,			Transfer Out			Dec. 31, 2013
							Gains (Losses)				Gains (Losses)			Issuances and			of Level 3 (a)
														Settlements, Net
	Asset-backed securities		$	749			$	—			$	—		$	—		$	(749	)	$	—
	Mortgage-backed securities		2,128				—				—			—			(2,128		)	—
Private equity investments		8,545				1,083				(1,960		)	(166		)	—			7,502
Real estate		3,472				(129		)		247			450			(1,741		)	2,299
Total		$	14,894			$	954			$	(1,713	)	$	284		$	(4,618	)	$	9,801
(a)	Transfers out of Level 3 into Level 2 were principally due to diminished use of unobservable inputs that were previously significant to these fair value measurements and were subsequently sold during 2013.
(Thousands of Dollars)		Jan. 1, 2012				Net Realized				Net Unrealized			Purchases,			Transfers Out of Level 3			Dec. 31, 2012
						Gains (Losses)				Gains (Losses)			Issuances and
													Settlements, Net
Asset-backed securities		$	1,578			$	197			$	(273	)	$	(753	)	$	—		$	749
Mortgage-backed securities		3,781				93				(112		)	(1,634		)	—			2,128
Private equity investments		8,440				945				(1,197		)	357			—			8,545
Real estate		2,008				1				328			1,135			—			3,472
Total		$	15,807			$	1,236			$	(1,254	)	$	(895	)	$	—		$	14,894
(Thousands of Dollars)		Jan. 1, 2011				Net Realized				Net Unrealized			Purchases,			Transfers Out of Level 3			Dec. 31, 2011
						Gains (Losses)				Gains (Losses)			Issuances and
													Settlements, Net
Asset-backed securities		$	1,367			$	121			$	(125	)	$	215		$	—		$	1,578
Mortgage-backed securities		5,984				55				(295		)	(1,963		)	—			3,781
Private equity investments		6,704				210				648			878			—			8,440
Real estate		3,746				(34		)		1,002			(2,706		)	—			2,008
Total		$	17,801			$	352			$	1,230		$	(3,576	)	$	—		$	15,807
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)		2013				2012
Accumulated Benefit Obligation at Dec. 31		$	153,894			$	169,939
Change in Projected Benefit Obligation:
Obligation at Jan. 1		$	179,995			$	159,766
Service cost		5,682				4,568
Interest cost		6,924				7,765
Plan amendments		(1,109		)		216
Actuarial (gain) loss		(11,097		)		21,083
Benefit payments		(16,465		)		(13,403		)
Obligation at Dec. 31		$	163,930			$	179,995
(Thousands of Dollars)		2013				2012
Change in Fair Value of Plan Assets:
Fair value of plan assets at Jan. 1		$	136,546			$	121,348
Actual return on plan assets		5,525				16,079
Employer contributions		11,329				12,522
Benefit payments		(16,465		)		(13,403		)
Fair value of plan assets at Dec. 31		$	136,935			$	136,546
(Thousands of Dollars)		2013				2012
Funded Status of Plans at Dec. 31:
Funded status (a)		$	(26,995	)		$	(43,449	)
(a)	Amounts are recognized in noncurrent liabilities on NSP-Wisconsin’s consolidated balance sheets.
(Thousands of Dollars)		2013				2012
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:
Net loss		$	84,773			$	99,338
Prior service cost		778				2,290
Total		$	85,551			$	101,628
(Thousands of Dollars)		2013				2012
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		$	7,631			$	6,895
Noncurrent regulatory assets		77,920				94,733
Total		$	85,551			$	101,628
Measurement date		Dec. 31, 2013		Dec. 31, 2012
		2013			2012
Significant Assumptions Used to Measure Benefit Obligations:
Discount rate for year-end valuation		4.75	%		4	%
Expected average long-term increase in compensation level		3.75			3.75
Mortality table		RP 2000			RP 2000
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. These regulations did not require cash funding for 2008 through 2010 for Xcel Energy’s pension plans. Required contributions were made in 2011, 2012 and 2013 to meet minimum funding requirements.
The following are the pension funding contributions, both voluntary and required, made by Xcel Energy for 2011 through January 2014:
•	In January 2014, contributions of $130.0 million were made across three of Xcel Energy’s pension plans, of which $8.0 million was attributable to NSP-Wisconsin;
•	In 2013, contributions of $192.4 million were made across four of Xcel Energy’s pension plans, of which $11.3 million was attributable to NSP-Wisconsin;
•	In 2012, contributions of $198.1 million were made across four of Xcel Energy’s pension plans, of which $12.5 million was attributable to NSP-Wisconsin;
•	In 2011, contributions of $137.3 million were made across three of Xcel Energy’s pension plans, of which $6.4 million was attributable to NSP-Wisconsin;
•	For future years, Xcel Energy and NSP-Wisconsin anticipate contributions will be made as necessary.
Plan Amendments — Xcel Energy, which includes NSP-Wisconsin, amended the plan in 2013 resulting in a decrease of the projected benefit obligation due to fully insuring the long-term disability benefit for NSP bargaining participants. This decrease was partially offset by an increase to the projected benefit obligation resulting from a change in the discount rate basis for lump sum conversion of annuities for participants in the Xcel Energy Pension Plan. In 2012, the plan was amended to allow a one time transfer of a portion of qualifying obligations from the nonqualified pension plan into the qualified pension plans.  Xcel Energy and NSP-Wisconsin also modified the benefit formula for nonbargaining new hires beginning in 2012 to a reduced benefit level.
Benefit Costs — The components of NSP-Wisconsin’s net periodic pension cost were:
(Thousands of Dollars)		2013				2012				2011
Service cost		$	5,682			$	4,568			$	4,271
Interest cost		6,924				7,765				8,031
Expected return on plan assets		(9,995		)		(10,489		)		(11,484		)
Amortization of prior service cost		417				1,771				1,895
Amortization of net loss		7,924				6,004				4,070
Net periodic pension cost		$	10,952			$	9,619			$	6,783
		2013			2012			2011
Significant Assumptions Used to Measure Costs:
Discount rate		4	%		5	%		5.5	%
Expected average long-term increase in compensation level		3.75			4			4
Expected average long-term rate of return on assets		7.25			7.5			8
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 $2.2 million, $1.8 million and $1.3 million in 2013, 2012 and 2011, 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 2014 pension cost calculations is 7.25 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 $1.3 million in 2013, $1.2 million in 2012 and $1.1 million in 2011.
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.  The former NSP, which includes NSP-Wisconsin, discontinued contributing toward health care benefits for nonbargaining employees retiring after 1998 and for bargaining employees who retired after 1999.
In 1993, Xcel Energy Inc. and NSP-Wisconsin adopted accounting guidance regarding other non-pension postretirement benefits and elected to amortize the unrecognized APBO on a straight-line basis over 20 years.
Regulatory agencies for nearly all retail and wholesale 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.  Also, a portion of the assets contributed on behalf of nonbargaining retirees has been funded into a sub-account of the Xcel Energy pension plans.  These assets are invested in a manner consistent with the investment strategy for the pension plan.
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.  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.  Investment-return 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 postretirement benefit plan assets that are measured at fair value as of Dec. 31, 2013 and 2012:
		Dec. 31, 2013
(Thousands of Dollars)		Level 1				Level 2				Level 3			Total
Cash equivalents		$	31			$	—			$	—		$	31
Derivatives		—				(2		)		—			(2		)
Government securities		—				89				—			89
Insurance contracts		—				80				—			80
Corporate bonds		—				79				—			79
Asset-backed securities		—				5				—			5
Mortgage-backed securities		—				37				—			37
Commingled funds		—				452				—			452
Other		—				(25		)		—			(25		)
Total		$	31			$	715			$	—		$	746
		Dec. 31, 2012
(Thousands of Dollars)		Level 1				Level 2				Level 3			Total
Cash equivalents		$	123			$	—			$	—		$	123
Government securities		—				99				—			99
Insurance contracts		—				67				—			67
Corporate bonds		—				59				—			59
Asset-backed securities		—				—				1			1
Mortgage-backed securities		—				—				54			54
Commingled funds		—				307				—			307
Other		—				(63		)		—			(63		)
Total		$	123			$	469			$	55		$	647
The following tables present the changes in NSP-Wisconsin’s Level 3 postretirement benefit plan assets for the years ended Dec. 31, 2013, 2012 and 2011:
(Thousands of Dollars)		Jan. 1, 2013				Net Realized				Net Unrealized			Purchases,			Transfers Out of Level 3 (a)			Dec. 31, 2013
						Gains (Losses)				Gains (Losses)			Issuances and
													Settlements, Net
Asset-backed securities		$	1			$	—			$	—		$	—		$	(1	)	$	—
Mortgage-backed securities		54				—				—			—			(54		)	—
Total		$	55			$	—			$	—		$	—		$	(55	)	$	—
(a)	Transfers out of Level 3 into Level 2 were principally due to diminished use of unobservable inputs that were previously significant to these fair value measurements and were subsequently sold during 2013.
(Thousands of Dollars)		Jan. 1, 2012				Net Realized				Net Unrealized			Purchases,			Transfers Out of Level 3			Dec. 31, 2012
						Gains (Losses)				Gains (Losses)			Issuances and
													Settlements, Net
Asset-backed securities		$	14			$	—			$	3		$	(16	)	$	—		$	1
Mortgage-backed securities		48				(1		)		6			1			—			54
Total		$	62			$	(1	)		$	9		$	(15	)	$	—		$	55
(Thousands of Dollars)		Jan. 1, 2011				Net Realized				Net Unrealized			Purchases,			Transfers Out of Level 3			Dec. 31, 2011
						Gains (Losses)				Gains (Losses)			Issuances and
													Settlements, Net
Asset-backed securities		$	6			$	—			$	(2	)	$	10		$	—		$	14
Mortgage-backed securities		45				(3		)		6			—			—			48
Total		$	51			$	(3	)		$	4		$	10		$	—		$	62
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)		2013				2012
Change in Projected Benefit Obligation:
Obligation at Jan. 1		$	19,432			$	22,127
Service cost		25				20
Interest cost		760				1,075
Medicare subsidy reimbursements		31				189
Plan amendments		—				(3,440		)
Plan participants’ contributions		621				893
Actuarial (gain) loss		(1,724		)		1,486
Benefit payments		(1,992		)		(2,918		)
Obligation at Dec. 31		$	17,153			$	19,432
(Thousands of Dollars)		2013				2012
Change in Fair Value of Plan Assets:
Fair value of plan assets at Jan. 1		$	647			$	746
Actual return on plan assets		(13		)		3
Plan participants’ contributions		621				893
Employer contributions		1,483				1,923
Benefit payments		(1,992		)		(2,918		)
Fair value of plan assets at Dec. 31		$	746			$	647
(Thousands of Dollars)		2013				2012
Funded Status of Plans at Dec. 31:
Funded status		$	(16,407	)		$	(18,785	)
Current liabilities		(718		)		(943		)
Noncurrent liabilities		(15,689		)		(17,842		)
Net postretirement amounts recognized on consolidated balance sheets		$	(16,407	)		$	(18,785	)
(Thousands of Dollars)		2013				2012
Amounts Not Yet Recognized as Components of Net Periodic Cost:
Net loss		$	11,098			$	13,730
Prior service credit		(3,187		)		(3,538		)
Transition obligation		—				1
Total		$	7,911			$	10,193
(Thousands of Dollars)		2013				2012
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		$	570			$	433
Noncurrent regulatory assets		7,341				9,760
Total		$	7,911			$	10,193
Measurement date		Dec. 31, 2013		Dec. 31, 2012
		2013			2012
Significant Assumptions Used to Measure Benefit Obligations:
Discount rate for year-end valuation		4.82	%		4.1	%
Mortality table		RP 2000			RP 2000
Health care costs trend rate — initial		7	%		7.5	%
Effective Jan. 1, 2014, the initial medical trend rate was decreased from 7.5 percent to 7.0 percent. The ultimate trend assumption remained at 4.5 percent. The period until the ultimate rate is reached is five years. Xcel Energy Inc. and NSP-Wisconsin base the medical trend assumption on the long-term cost inflation expected in the health care market, considering the levels projected and recommended by industry experts, as well as recent actual medical cost increases experienced by the retiree medical plan.
A one-percent change in the assumed health care cost trend rate would have the following effects on NSP-Wisconsin:
		One-Percentage Point
(Thousands of Dollars)		Increase				Decrease
APBO		$	1,773			$	(1,486	)
Service and interest components		78				(61		)
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, as discussed previously. Xcel Energy, which includes NSP-Wisconsin, contributed $17.6 million, $47.1 million and $49.0 million during 2013, 2012 and 2011, respectively, of which $1.5 million, $1.9 million and $2.4 million were attributable to NSP-Wisconsin. Xcel Energy expects to contribute approximately $13.3 million during 2014, of which $1.5 million is attributable to NSP-Wisconsin.
Plan Amendments — The 2012 decrease of the projected Xcel Energy and NSP-Wisconsin postretirement health and welfare benefit obligation for plan amendments is due to the expected transition of certain participant groups to an external plan administrator.
Benefit Costs — The components of NSP-Wisconsin’s net periodic postretirement benefit cost were:
(Thousands of Dollars)		2013				2012				2011
Service cost		$	25			$	20			$	17
Interest cost		760				1,075				1,144
Expected return on plan assets		(42		)		(50		)		(74		)
Amortization of transition obligation		1				171				171
Amortization of prior service credit		(351		)		(14		)		(14		)
Amortization of net loss		963				486				366
Net periodic postretirement benefit cost		$	1,356			$	1,688			$	1,610
		2013			2012			2011
Significant Assumptions Used to Measure Costs:
Discount rate		4.1	%		5	%		5.5	%
Expected average long-term rate of return on assets		7.11			6.75			7.5
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				Gross Projected				Expected Medicare			Net Projected
		Benefit Payments				Postretirement				Part D Subsidies			Postretirement
						Health Care							Health Care
						Benefit Payments							Benefit Payments
2014		$	21,677			$	1,491			$	27		$	1,464
2015		14,257				1,459				25			1,434
2016		13,420				1,444				24			1,420
2017		13,851				1,384				20			1,364
2018		12,983				1,357				18			1,339
2019-2023		64,935				6,229				82			6,147
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, 2013, 2012 and 2011.  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)		2013				2012				2011
Multiemployer plan contributions:
Pension		$	130			$	163			$	169
Total		$	130			$	163			$	169

Other_Income_Net

Other Income, Net	12 Months Ended
	Dec. 31, 2013
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)	2013			2012			2011
	Interest income	$	538		$	736		$	324
	Other nonoperating income	152			129			67
	Insurance policy expense	(427		)	(389		)	(283		)
	Other nonoperating expense	(10		)	—			(10		)
	Other income, net	$	253		$	476		$	98

Fair_Value_of_Financial_Assets

Fair Value of Financial Assets and Liabilities	12 Months Ended
	Dec. 31, 2013
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 net asset values.
	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, 2013, 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, 2013 and 2012:
	(Amounts in Thousands) (a)(b)		Dec. 31, 2013			Dec. 31, 2012
	MMBtu of natural gas		987			53
	(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)		2013				2012			2011
	Accumulated other comprehensive loss related to cash flow hedges at Jan. 1		$	(437	)		$	(514	)	$	(590	)
	After-tax net realized losses on derivative transactions reclassified into earnings		76				77			76
	Accumulated other comprehensive loss related to cash flow hedges at Dec. 31		$	(361	)		$	(437	)	$	(514	)
	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, 2013, 2012 and 2011.
	During the year ended Dec. 31, 2013, 2012 and 2011, changes in the fair value of natural gas commodity derivatives resulted in net losses of $0.1 million, $0.4 million and $3.6 million, respectively, recognized as regulatory assets and liabilities. The classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms.
	Natural gas commodity derivatives settlement losses and option premium amortization totaling $0.7 million, $2.9 million and $2.9 million were recognized for each of the years ended Dec. 31, 2013, 2012 and 2011, 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, 2013, 2012 and 2011. 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, 2013
			Fair Value
	(Thousands of Dollars)		Level 1				Level 2			Level 3			Fair Value		Counterparty		Total (b)
													Total		Netting (a)
	Current derivative assets
	Natural gas commodity		$	—			$	580		$	—		$	580	$	—	$	580
			Dec. 31, 2012
			Fair Value
	(Thousands of Dollars)		Level 1				Level 2			Level 3			Fair Value		Counterparty		Total (c)
													Total		Netting (a)
	Current derivative liabilities
	Natural gas commodity		$	—			$	11		$	—		$	11	$	—	$	11
	(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, 2013 and 2012.  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 other current assets balance of $5.1 million at Dec. 31, 2013 in the consolidated balance sheets.
	(c)	Included in other current liabilities balance of $11.0 million at Dec. 31, 2012 in the consolidated balance sheets.
	Fair Value of Long-Term Debt
	As of Dec. 31, 2013 and 2012, other financial instruments for which the carrying amount did not equal fair value were as follows:
			2013							2012
	(Thousands of Dollars)		Carrying Amount				Fair Value			Carrying Amount			Fair Value
	Long-term debt, including current portion		$	468,597			$	518,269		$	468,563		$	576,353
	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, 2013 and 2012, and given the observability of the inputs to these estimates, the fair values presented for long-term debt have been assigned a Level 2.

Rate_Matters_Notes

Rate Matters (Notes)	12 Months Ended
	Dec. 31, 2013
Public Utilities, General Disclosures [Abstract]	'
Rate Matters	'
	Rate Matters
	Recently Concluded Regulatory Proceedings — PSCW
	Wisconsin 2014 Electric and Gas Rate Case — In May 2013, NSP-Wisconsin filed a request with the PSCW to increase rates for electric and natural gas service effective Jan. 1, 2014. NSP-Wisconsin requested an overall increase in annual electric rates of $40.0 million, or 6.5 percent, and an increase in natural gas rates of $4.7 million, or 3.8 percent. The electric rate increase included a $4.5 million adjustment related to proceeds from a nuclear settlement agreement with the DOE.
	The rate filing was based on a 2014 forecast test year, an ROE of 10.4 percent, an equity ratio of 52.5 percent, and a forecasted average rate base of approximately $895.3 million for the electric utility and $89.8 million for the natural gas utility.
	In October 2013, NSP-Wisconsin filed rebuttal testimony revising the requested electric rate increase to $34.3 million and natural gas rate increase to zero, based on a 10.4 percent ROE and other adjustments.
	In December 2013, the PSCW approved an electric rate increase of approximately $19.5 million or 3.1 percent based on a 10.2 percent ROE and an equity ratio of 52.5 percent. The PSCW also approved cost deferrals of $4.1 million for interchange agreement amounts from NSP-Minnesota related to the Monticello EPU project until the MPUC completes its prudence review. The PSCW did not change rates for NSP-Wisconsin’s natural gas utility. New electric rates went into effect on Jan. 1, 2014.

Commitments_and_Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2013
Commitments and Contingencies Disclosure [Abstract]	'
Commitments and Contingencies	'
	Commitments and Contingencies
	Commitments
	Capital Commitments — NSP-Wisconsin has made commitments in connection with a portion of its projected capital expenditures. NSP-Wisconsin’s capital commitments primarily relate to one major project, CapX2020.
	CapX2020 — CapX2020 is an alliance of electric cooperatives, municipals and investor-owned utilities in the upper Midwest, including the NSP System that has proposed several groups of transmission projects to be completed by 2020.  Group 1 project investments consist of four transmission lines.  Major construction began in 2010 on the Group 1 transmission lines with an expected completion date in 2015.  NSP System’s investment depends on the routes and configurations approved by affected state commissions and on the allocation of costs borne by other participating utilities in the upper Midwest.
	Fuel Contracts — NSP-Wisconsin has entered into various long-term commitments providing for the purchase and delivery of a significant portion of its current coal and natural gas requirements.  These contracts expire in various years between 2014 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, 2013 are as follows:
	(Millions of dollars)		Coal		Natural gas		Natural gas
					supply		storage and
							transportation
	2014		$	6.2	$	13.4	$	11.9
	2015		1.3		0.3		11.6
	2016		0.7		0.3		11.7
	2017		0.7		0.2		9.5
	2018		0.7		—		4.4
	Thereafter		4.1		—		18.9
	Total (a)		$	13.7	$	14.2	$	68
	(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, trucks, aircraft, cars and power-operated equipment, are accounted for as operating leases.  Total expenses under operating lease obligations were approximately $1.4 million, $1.1 million and $1.4 million for 2013, 2012 and 2011, respectively.
	Future commitments under operating leases are:
	(Millions of Dollars)
	2014		$	0.8
	2015		0.8
	2016		0.8
	2017		0.9
	2018		0.9
	Thereafter		8.8
	Total		$	13
	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 in the future, 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, 2013		Dec. 31, 2012
	Current assets		$	223	$	357
	Property, plant and equipment, net		2,427		2,599
	Other noncurrent assets		112		105
	Total assets		$	2,762	$	3,061
	Current liabilities		$	233	$	1,388
	Mortgages and other long-term debt payable		1,687		617
	Other noncurrent liabilities		42		39
	Total liabilities		$	1,962	$	2,044
	Joint Operating System — The electric production and transmission system of NSP-Wisconsin is managed as an integrated system with that of NSP-Minnesota, jointly referred to as the NSP System.  The electric production and transmission costs of the entire NSP System are shared by NSP-Minnesota and NSP-Wisconsin.  A FERC approved agreement between the two companies, called the Interchange Agreement, provides for the sharing of all costs of generation and transmission facilities of the system, including capital costs. Such costs include current and potential obligations of NSP-Minnesota related to its nuclear generating facilities.
	NSP-Minnesota’s public liability for claims resulting from any nuclear incident is limited to $13.6 billion under the Price-Anderson amendment to the Atomic Energy Act.  NSP-Minnesota has secured $375 million of coverage for its public liability exposure with a pool of insurance companies.  The remaining $13.2 billion of exposure is funded by the Secondary Financial Protection Program, available from assessments by the federal government in case of a nuclear accident.  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 million per reactor 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 $16.1 million for business interruption insurance and $40.2 million for property damage insurance if losses exceed accumulated reserve funds.
	Guarantees — NSP-Wisconsin provides a guarantee for payment of customer loans related to NSP-Wisconsin’s farm rewiring program. NSP-Wisconsin’s exposure under the guarantee is based upon the net liability under the agreement.  The guarantee issued by NSP-Wisconsin limits the exposure of NSP-Wisconsin to a maximum amount stated in the guarantee.  The guarantee contains no recourse provisions and requires no collateral.
	The following table presents the guarantee issued and outstanding for NSP-Wisconsin:
	(Millions of Dollars)		Guarantee		Current		Term or		Triggering
			Amount		Exposure		Expiration Date		Event
									Requiring
									Performance
	Guarantee of customer loans for the Farm Rewiring Program		$	1	$	0.3	2017		(a)
	(a)	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 hazardous materials and 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 Ashland site) includes property owned by NSP-Wisconsin, which was a site previously operated by a predecessor company as a MGP facility (the Upper Bluff), and two other properties: an adjacent city lakeshore park area (Kreher Park), on which an unaffiliated third party previously operated a sawmill and conducted creosote treating operations; and an area of Lake Superior’s Chequamegon Bay adjoining the park (the Sediments).
	The EPA issued its Record of Decision (ROD) in 2010, which describes the preferred remedy the EPA has selected for the cleanup of the Ashland site. For the Sediments at the Ashland Site, the ROD preferred remedy is a hybrid remedy involving both dry excavation and wet conventional dredging methodologies (the Hybrid Remedy). The ROD also identifies the possibility of a wet conventional dredging only remedy for the Sediments (the Wet Dredge), contingent upon the completion of a successful Wet Dredge pilot study.
	In 2011, the EPA issued special notice letters identifying several entities, including NSP-Wisconsin, as PRPs, for future remediation at the site. The special notice letters requested that those PRPs participate in negotiations with the EPA regarding how the PRPs intended to conduct or pay for the remediation at the Ashland site. As a result of settlement negotiations with NSP-Wisconsin, the EPA agreed to segment the Ashland site into separate areas. The first area (Phase I Project Area) includes soil and groundwater in Kreher Park and the Upper Bluff. The second area includes the Sediments.
	In October 2012, a settlement among the EPA, the WDNR, the Bad River and Red Cliff Bands of the Lake Superior Tribe of Chippewa Indians and NSP-Wisconsin was approved by the U.S. District Court for the Western District of Wisconsin. This settlement resolves claims against NSP-Wisconsin for its alleged responsibility for the remediation of the Phase I Project Area. Under the terms of the settlement, NSP-Wisconsin agreed to perform the remediation of the Phase I Project Area, but does not admit any liability with respect to the Ashland site. The settlement reflects a cost estimate for the clean up of the Phase I Project Area of $40 million. The settlement also resolves claims by the federal, state and tribal trustees against NSP-Wisconsin for alleged natural resource damages at the Ashland site, including both the Phase I Project Area and the Sediments. As part of the settlement, NSP-Wisconsin has conveyed approximately 1,390 acres of land to the State of Wisconsin and tribal trustees. Fieldwork to address the Phase I Project Area at the Ashland site began at the end of 2012 and continues.
	Negotiations are ongoing between the EPA and NSP-Wisconsin regarding who will pay or perform the cleanup of the Sediments and what remedy will be implemented at the site to address the Sediments. In August and September 2013, NSP-Wisconsin performed field studies in the Sediments to gather more data about site conditions. The data from that investigation was received and reported to the EPA at the end of 2013. It is NSP-Wisconsin’s view that this data demonstrates the Hybrid Remedy is not safe or feasible to implement. The EPA’s ROD for the Ashland site includes estimates that the cost of the Hybrid Remedy is between $63 million and $77 million, with a potential deviation in such estimated costs of up to 50 percent higher to 30 percent lower. Also, in September 2013, the EPA requested NSP-Wisconsin consider re-submitting another proposal to perform a Wet Dredge pilot study for a portion of the Sediments. NSP-Wisconsin previously submitted a proposal for a Wet Dredge pilot study in 2011. In November 2013, NSP-Wisconsin submitted a revised Wet Dredge pilot study work plan proposal to the EPA. NSP-Wisconsin is in the process of negotiating a final pilot study work plan for possible implementation in late summer or early fall of 2014.
	In August 2012, NSP-Wisconsin also filed litigation against other PRPs for their share of the cleanup costs for the Ashland site. Trial for this matter is scheduled for April 2015. Negotiations between the EPA, NSP-Wisconsin and several of the other PRPs regarding the PRPs’ fair share of the cleanup costs for the Ashland site are also ongoing.
	At Dec. 31, 2013 and 2012, NSP-Wisconsin had recorded a liability of $104.6 million and $103.7 million, respectively, for the Ashland site based upon potential remediation and design costs together with estimated outside legal and consultant costs; of which $25.2 million and $20.1 million, respectively, was considered a current liability. NSP-Wisconsin’s potential liability, the actual cost of remediation and the time frame over which the amounts may be paid are subject to change. NSP-Wisconsin also continues to work to identify and access state and federal funds to apply to the ultimate remediation cost of the entire site. Unresolved issues or factors that could result in higher or lower NSP-Wisconsin remediation costs for the Ashland site include the cleanup approach implemented for the Sediments, which party implements the cleanup, the timing of when the cleanup is implemented, potential contributions by other PRPs and whether federal or state funding may be directed to help offset remediation costs at the Ashland site.
NSP-Wisconsin has deferred the estimated site remediation costs, as a regulatory asset, based on an expectation that the PSCW will continue to allow NSP-Wisconsin to recover payments for environmental remediation from its customers. The PSCW has consistently authorized in NSP-Wisconsin rates recovery of all remediation costs incurred at the Ashland site, and has authorized recovery of MGP remediation costs by other Wisconsin utilities. External MGP remediation costs are subject to deferral in the Wisconsin retail jurisdiction and are reviewed for prudence as part of the Wisconsin retail rate case process. Under an existing PSCW policy, utilities have recovered remediation costs for MGPs in natural gas rates, amortized over a four- to six-year period. The PSCW historically has not allowed utilities to recover their carrying costs on unamortized regulatory assets for MGP remediation.
In the 2013 rate case decision, the PSCW recognized the potential magnitude of the future liability for the cleanup at the Ashland site and granted an exception to its existing policy at the request of NSP-Wisconsin. The elements of this exception include: 1) approval to begin recovery of estimated Phase 1 Project costs beginning on Jan. 1, 2013; 2) approval to amortize these estimated costs over a ten-year period; and 3) approval to apply a three percent carrying cost to the unamortized regulatory asset. In the 2014 rate case decision, the PSCW continued the cost recovery treatment established in the 2013 rate case, with respect to the 2013 and 2014 clean-up costs for the Phase I Project Area. The PSCW determined the timing of the clean-up of the Sediments was uncertain and declined NSP-Wisconsin’s request to begin cost recovery for this portion of the clean-up in 2014 rates. However, the PSCW allowed NSP-Wisconsin to increase its 2014 amortization expense related to the clean-up by an additional $1.1 million to offset the need for a rate decrease for the natural gas utility. The cost recovery treatment granted by the PSCW in the 2013 and 2014 rate cases will help mitigate the rate impact to natural gas customers and the risk to NSP-Wisconsin from a longer amortization period.
Other MGP Sites — NSP-Wisconsin is currently involved in investigating and/or remediating several other MGP sites where hazardous or other regulated materials may have been deposited. NSP-Wisconsin has identified two sites, where former MGP activities have or may have resulted in site contamination and are under current investigation and/or remediation. At some or all of these MGP sites, there are other parties that may have responsibility for some portion of any remediation. NSP-Wisconsin anticipates that the majority of the remediation at these sites will continue through at least 2014. NSP-Wisconsin had accrued $3.9 million and $2.5 million for both of these sites at Dec. 31, 2013 and 2012, 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 June 2013, the EPA published a proposed 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. Refuse derived fuel, biomass and other alternatively fueled power plants are not addressed by the proposed revisions. The proposed rule identifies four potential regulatory options and invites comments on those regulatory approaches. The options differ in the number of waste streams covered, size of the units controlled and stringency of controls. It is not yet known when the EPA will issue a finalized rule. Under the current proposed rule, facilities would need to comply as soon as possible after July 2017 but no later than July 2022. The impact of this rule on NSP-Wisconsin is uncertain at this time.
Federal CWA Section 316 (b) — The federal CWA requires the EPA to regulate cooling water intake structures to assure that these structures reflect the best technology available for minimizing adverse environmental impacts to aquatic species. In 2011, the EPA published the proposed rule that sets standards for minimization of aquatic species impingement, but leaves entrainment reduction requirements at the discretion of the permit writer and the regional EPA office. A final rule is anticipated in April 2014. It is not possible to provide an accurate estimate of the overall cost of this rulemaking at this time due to the uncertainty of the final regulatory requirements.
Proposed Coal Ash Regulation — NSP-Wisconsin’s operations are subject to federal and state laws that impose requirements for handling, storage, treatment and disposal of hazardous waste. In 2010, the EPA published a proposed rule on whether to regulate coal combustion byproducts (coal ash) as hazardous or nonhazardous waste. Coal ash is currently exempt from hazardous waste regulation. NSP-Wisconsin’s costs for the management and disposal of coal ash would significantly increase and the beneficial reuse of coal ash would be negatively impacted if the EPA ultimately issues a rule under which coal ash is regulated as hazardous waste. The EPA has entered into a consent decree to act on final regulations by December 2014. The timing, scope and potential cost of any final rule that might be implemented are not determinable at this time.
Air
EPA GHG Regulation — In 2009, the EPA issued its “endangerment” finding that GHG emissions pose a threat to public health and welfare. This finding required the EPA to adopt GHG emission standards for mobile sources. In 2011, new EPA permitting requirements became effective for GHG emissions of new and modified large stationary sources, which are applicable to the construction of new power plants or power plant modifications that increase emissions above a certain threshold. These rules were upheld on appeal to the D.C. Circuit. The U.S. Supreme Court has granted review on one issue related to these rules, specifically whether the EPA’s regulation of GHG emissions from mobile sources triggered, by operation of law, new source review permitting requirements for stationary sources, which was the EPA’s basis for adopting the 2011 permitting rules. The Court is scheduled to hear arguments in February 2014. A ruling is anticipated by June 2014. NSP-Wisconsin is unable to determine the cost of compliance with these new EPA requirements as it is not clear whether these requirements will apply to future changes at NSP-Wisconsin’s power plants.
GHG Emission Standard for Existing Sources and NSPS Proposal — In June 2013, President Obama issued a memorandum directing the EPA to develop GHG emission standards for existing power plants. The memorandum anticipates the EPA will issue a proposed GHG emission standard for existing power plants in June 2014. It is not possible to evaluate the impact of existing source standards until the upcoming proposal and final requirements are known.
In January 2014, the EPA re-proposed a GHG NSPS for newly constructed power plants which seeks to establish CO2 emission rates for coal-fired power plants that reflect emission reductions using partial carbon capture and storage technology (CCS). The EPA’s proposed CO2 emission limits for gas-fired power plants reflect emissions levels from combined cycle technology with no CCS. The EPA continues to propose that the NSPS not apply to modified or reconstructed existing power plants. In addition, installation of control equipment on existing plants would not constitute a “modification” to those plants under the NSPS program. It is not possible to evaluate the impact of the re-proposed NSPS until its final requirements are known.
CSAPR — In 2011, the EPA issued the CSAPR to address 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. The CSAPR would have set more stringent requirements than the proposed Clean Air Transport Rule. The rule also would have created an emissions trading program.
In August 2012, the D.C. Circuit vacated the CSAPR and remanded it back to the EPA. The D.C. Circuit stated that the EPA must continue administering the CAIR pending adoption of a valid replacement. In December 2013, the U.S. Supreme Court heard oral arguments on the D.C. Circuit’s 2012 decision to vacate the CSAPR. A decision is anticipated by June 2014. It is not yet known whether the D.C. Circuit’s decision will be upheld, or how the EPA might approach a replacement rule. Therefore, it is not known what requirements may be imposed in the future.
As the EPA continues administering the CAIR while the CSAPR or a replacement rule is pending, NSP-Wisconsin expects to comply with the CAIR as described below.
CAIR — In 2005, the EPA issued the CAIR to further regulate SO2 and NOx emissions. Under the CAIR’s cap and trade structure, companies can comply through capital investments in emission controls or purchase of emission allowances from other utilities making reductions on their systems. NSP-Wisconsin purchased allowances in 2012 and 2013 and plans to continue to purchase allowances in 2014 to comply with the CAIR. At Dec. 31, 2013, the estimated annual CAIR NOx allowance cost for NSP-Wisconsin did not have a material impact on the results of operations, financial position or cash flows.
Electric Generating Unit (EGU) Mercury and Air Toxics Standards (MATS) Rule — The final EGU MATS rule became effective in April 2012. The EGU MATS rule sets emission limits for acid gases, mercury and other hazardous air pollutants and requires coal-fired utility facilities greater than 25 MW to demonstrate compliance within three to four years of the effective date. NSP-Wisconsin will not have any units subject to EGU MATS because it will cease coal combustion in Bay Front Unit 5.
Industrial Boiler (IB) MACT Rules — In 2011, the EPA finalized IB MACT rules to regulate boilers and process heaters fueled with coal, biomass and liquid fuels, which would apply to NSP-Wisconsin’s Bay Front Units 1 and 2. The capital cost to install controls to meet the requirements in the final reconsidered rule is anticipated to be $17.2 million in total and is targeted for completion in 2014.
Revisions to National Ambient Air Quality Standards (NAAQS) for PM — In December 2012, the EPA lowered the primary health-based NAAQS for annual average fine PM and retained the current daily standard for fine PM. In areas where NSP-Wisconsin operates power plants, current monitored air concentrations are below the level of the final annual primary standard. The EPA is expected to designate non-compliant locations by December 2014. States would then study the sources of the nonattainment and make emission reduction plans to attain the standards. It is not possible to evaluate the impact of this regulation further until the final designations have been made.
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 transmission and distribution, and general property.  The electric production obligations include ash-containment facilities, storage tanks, control panels and asbestos.  The asbestos recognition associated with the steam production includes certain plants.  This asbestos abatement removal obligation originated in 1973 with the CAA, which applied to the demolition of buildings or removal of equipment containing asbestos that can become airborne on removal.  The electric transmission and distribution ARO consists of many small potential obligations associated with PCBs, mineral oil, storage tanks, treated poles, lithium batteries, mercury and street lighting lamps.  The common general AROs include small obligations related to storage tanks and office buildings. These assets have numerous in-service dates for which it is difficult to assign the obligation to a particular year. Therefore, the obligation was measured using an average service life.
A reconciliation of NSP-Wisconsin’s AROs is shown in the tables below for the years ended Dec. 31, 2013 and 2012, respectively:
(Thousands of Dollars)		Beginning Balance		Liabilities Recognized		Accretion			Revisions to			Ending Balance
		Jan. 1, 2013							Prior Estimates			Dec. 31, 2013 (a)
Electric plant
Steam production asbestos		$	1,962	$	—	$	43		$	—		$	2,005
Steam and other production ash containment		125		—		12			224			361
Electric distribution		13		—		1			22			36
Other		826		—		20			(557		)	289
Natural gas plant
Gas transmission and distribution		75		—		5			(5		)	75
Common and other property
Common miscellaneous		35		—		3			49			87
Total liability (b)		$	3,036	$	—	$	84		$	(267	)	$	2,853
(Thousands of Dollars)		Beginning Balance		Liabilities Recognized		Accretion			Revisions to			Ending Balance
		Jan. 1, 2012							Prior Estimates			Dec. 31, 2012 (a)
Electric plant
Steam production asbestos		$	—	$	1,962	$	—		$	—		$	1,962
Steam and other production ash containment		120		—		5			—			125
Electric distribution		13		—		—			—			13
Other		186		—		7			633			826
Natural gas plant
Gas transmission and distribution		71		—		4			—			75
Common and other property
Common miscellaneous		34		—		1			—			35
Total liability (b)		$	424	$	1,962	$	17		$	633		$	3,036
(a)	There were no ARO liabilities settled during the 12 months ended Dec. 31, 2013 or 2012.
(b)	Included in the other long-term liabilities balance in the consolidated balance sheets.
In 2013, NSP-Wisconsin revised ash containment facilities, miscellaneous electric production, electric transmission and distribution, natural gas transmission and distribution and common general AROs due to revised estimated cash flows. In 2012, NSP-Wisconsin revised electric transmission and distribution AROs due to revised estimated cash flows.  Additionally, in 2012, an ARO was recorded to reflect the expected costs with asbestos abatement at certain steam production facilities.
Removal Costs — NSP-Wisconsin records a regulatory liability for plant removal costs of steam and other generation, transmission and distribution facilities. 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 periods over which the amounts were accrued and the changing of rates through 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, 2013 and 2012 were $116 million and $114 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.

Regulatory_Assets_and_Liabilit

Regulatory Assets and Liabilities	12 Months Ended
	Dec. 31, 2013
Regulatory Assets and Liabilities Disclosure [Abstract]	'
Regulatory Assets and Liabilities	'
	Regulatory Assets and Liabilities
	NSP-Wisconsin’s consolidated financial statements are prepared in accordance with the applicable accounting guidance, as discussed in Note 1.  Under this guidance, regulatory assets and liabilities are created for amounts that regulators may allow to be collected, or may require to be paid back to customers in future electric and natural gas rates.  Any portion of the business that is not rate regulated cannot establish regulatory assets and liabilities.  If changes in the utility industry or the business of NSP-Wisconsin no longer allow for the application of regulatory accounting guidance under GAAP, NSP-Wisconsin would be required to recognize the write-off of regulatory assets and liabilities in net income or OCI.
	The components of regulatory assets shown on the consolidated balance sheets of NSP-Wisconsin at Dec. 31, 2013 and 2012 are:
	(Thousands of Dollars)		See Note(s)	Remaining	Dec. 31, 2013				Dec. 31, 2012
				Amortization Period
	Regulatory Assets				Current		Noncurrent		Current		Noncurrent
	Environmental remediation costs		1, 11	Various	$	4,376	$	117,684	$	2,521	$	109,162
	Pension and retiree medical obligations (a)		7	Various	8,202		85,220		7,328		104,426
	Recoverable deferred taxes on AFUDC recorded in plant		1	Plant lives	—		12,679		—		10,458
	Losses on reacquired debt		4	Term of related debt	801		5,737		800		6,538
	State commission adjustments		1	Plant lives	410		9,355		339		7,533
	Conservation programs		1	Less than one year	404		—		691		—
	Deferred income tax adjustment		1, 6	Typically plant lives	—		1,763		—		1,974
	Recoverable purchased natural gas and electric energy costs			Less than one year	673		—		358		—
	Other			Various	—		755		11		368
	Total regulatory assets				$	14,866	$	233,193	$	12,048	$	240,459
	(a)	Includes the non-qualified pension plan.
	The components of regulatory liabilities shown on the consolidated balance sheets of NSP-Wisconsin at Dec. 31, 2013 and 2012 are:
	(Thousands of Dollars)		See Note(s)	Remaining	Dec. 31, 2013				Dec. 31, 2012
				Amortization Period
	Regulatory Liabilities				Current		Noncurrent		Current		Noncurrent
	Plant removal costs		11	Plant lives	$	—	$	116,293	$	—	$	113,949
	DOE settlement		11	Less than one year	6,814		—		5,628		—
	Investment tax credit deferrals		1, 6	Various	—		9,976		—		9,626
	Conservation programs		1	Less than one year	1,187		—		73		—
	Deferred electric production and natural gas costs		1	Less than one year	1,542		—		134		—
	Other			Various	174		155		251		171
	Total regulatory liabilities				$	9,717	$	126,424	$	6,086	$	123,746
	At Dec. 31, 2013 and 2012, approximately $0.1 million and $0.4 million of NSP-Wisconsin’s regulatory assets represented past expenditures not currently earning a return, respectively.  This amount primarily includes recoverable purchased natural gas and electric energy costs.

Other_Comprehensive_Income

Other Comprehensive Income	12 Months Ended
	Dec. 31, 2013
Stockholders' Equity Note [Abstract]	'
Other Comprehensive Income	'
	Other Comprehensive Income
	Changes in accumulated other comprehensive loss, net of tax, for the year ended Dec. 31, 2013 were as follows:
	(Thousands of Dollars)		Gains and
			Losses on Cash
			Flow Hedges
	Accumulated other comprehensive loss at Jan. 1		$	(437	)
	Losses reclassified from net accumulated other comprehensive loss		76
	Net current period OCI		76
	Accumulated other comprehensive loss at Dec. 31		$	(361	)
	Reclassifications from accumulated other comprehensive loss for the year ended Dec. 31, 2013 were as follows:
	(Thousands of Dollars)		Amounts
			Reclassified from
			Accumulated Other
			Comprehensive Loss
	Losses on cash flow hedges:
	Interest rate derivatives		$	127		(a)
	Total, pre-tax		127
	Tax benefit		(51		)
	Total amounts reclassified, net of tax		$	76
	(a)	Included in interest charges.

Segments_and_Related_Informati

Segments and Related Information	12 Months Ended
	Dec. 31, 2013
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.  In addition, this segment includes sales for resale and provides wholesale transmission service to various entities primarily in Wisconsin.
	•	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		Regulated		All Other			Reconciling			Consolidated
			Electric		Natural Gas					Eliminations			Total
	2013
	Operating revenues (a)		$	789,168	$	132,867	$	1,003		$	—		$	923,038
	Intersegment revenues		350		1,967		—			(2,317		)	—
	Total revenues		$	789,518	$	134,834	$	1,003		$	(2,317	)	$	923,038
	Depreciation and amortization		$	64,237	$	12,485	$	175		$	—		$	76,897
	Interest charges and financing costs		22,966		2,749		101			—			25,816
	Income tax expense (benefit)		33,691		4,623		(1,905		)	—			36,409
	Net Income		51,334		6,501		1,633			—			59,468
	(Thousands of Dollars)		Regulated		Regulated		All Other			Reconciling			Consolidated
			Electric		Natural Gas					Eliminations			Total
	2012
	Operating revenues (a)		$	757,565	$	103,100	$	1,177		$	—		$	861,842
	Intersegment revenues		355		727		—			(1,082		)	—
	Total revenues		$	757,920	$	103,827	$	1,177		$	(1,082	)	$	861,842
	Depreciation and amortization		$	59,768	$	9,251	$	215		$	—		$	69,234
	Interest charges and financing costs		20,303		2,554		80			—			22,937
	Income tax expense		27,164		2,113		281			—			29,558
	Net Income		45,377		3,094		1,480			—			49,951
	(Thousands of Dollars)		Regulated		Regulated		All Other			Reconciling			Consolidated
			Electric		Natural Gas					Eliminations			Total
	2011
	Operating revenues (a)		$	755,136	$	119,447	$	1,207		$	—		$	875,790
	Intersegment revenues		405		1,581		—			(1,986		)	—
	Total revenues		$	755,541	$	121,028	$	1,207		$	(1,986	)	$	875,790
	Depreciation and amortization		$	58,800	$	9,599	$	175		$	—		$	68,574
	Interest charges and financing costs		21,181		2,675		137			—			23,993
	Income tax expense (benefit)		32,656		1,995		(1,037		)	—			33,614
	Net Income		47,093		2,964		949			—			51,006
	(a)	Operating revenues include $137 million, $125 million and $124 million of intercompany revenue for the years ended Dec. 31, 2013, 2012 and 2011, respectively. See Note 15 for further discussion of related party transactions by operating segment.

Related_Party_Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2013
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)	2013		2012		2011
	Operating revenues:
	Electric	$	136,917	$	125,344	$	124,334
	Operating expenses:
	Purchased power	416,173		405,016		399,649
	Transmission expense	42,460		44,942		40,870
	Natural gas purchased for resale	97		116		98
	Other operating expenses — paid to Xcel Energy Services Inc.	61,531		54,137		54,885
	Interest expense	22		22		48
	Accounts receivable and payable with affiliates at Dec. 31 were:
		2013				2012
	(Thousands of Dollars)	Accounts		Accounts		Accounts		Accounts
		Receivable		Payable		Receivable		Payable
	NSP-Minnesota	$	—	$	18,584	$	—	$	26,632
	PSCo	—		8		—		71
	SPS	26		—		—		4
	Other subsidiaries of Xcel Energy Inc.	1,569		6,394		586		4,849
		$	1,595	$	24,986	$	586	$	31,556

Schedule_II_Valuation_and_Qual

Schedule II, Valuation and Qualifying Accounts	12 Months Ended
	Dec. 31, 2013
Valuation and Qualifying Accounts [Abstract]	'
Schedule II, Valuation and Qualifying Accounts	'
	NSP-WISCONSIN AND SUBSIDIARIES
	VALUATION AND QUALIFYING ACCOUNTS
	YEARS ENDED DEC. 31, 2013, 2012 AND 2011
	(amounts in thousands)
				Additions
		Balance at		Charged to Costs and Expenses		Charged to Other		Deductions from		Balance at
		Jan. 1				Accounts(a)		Reserves(b)		Dec. 31
	Allowance for bad debts:
	2013	$	4,333	$	3,988	$	1,199	$	4,609	$	4,911
	2012	4,766		3,329		1,310		5,072		4,333
	2011	4,262		3,842		1,241		4,579		4,766
	(a)	Recovery of amounts previously written off.
	(b)	Principally bad debts written off.

Summarized_Quarterly_Financial

Summarized Quarterly Financial Data (Unaudited)	12 Months Ended
	Dec. 31, 2013
Quarterly Financial Information Disclosure [Abstract]	'
Summarized Quarterly Financial Data (Unaudited)	'
	Summarized Quarterly Financial Data (Unaudited)
		Quarter Ended
	(Thousands of Dollars)	March 31, 2013		June 30, 2013		Sept. 30, 2013		Dec. 31, 2013
	Operating revenues	$	241,415	$	210,175	$	231,060	$	240,388
	Operating income	37,401		22,466		40,769		16,545
	Net income	19,685		10,544		22,013		7,225
		Quarter Ended
	(Thousands of Dollars)	March 31, 2012		June 30, 2012		Sept. 30, 2012		Dec. 31, 2012
	Operating revenues	$	223,799	$	194,173	$	226,475	$	217,395
	Operating income	28,914		14,348		40,735		15,869
	Net income	14,878		5,742		22,200		7,131

Summary_of_Significant_Account1

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2013
Accounting Policies [Abstract]	'
Business and System of Accounts	'
	Business and System of Accounts — NSP-Wisconsin is principally 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 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, AROs, 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, 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 sheet.  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 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.
	Requests can be made for recovery of purchased electric energy or fuel for generation prospectively through the rate review process, which normally occurs every two years, or at an interim fuel cost hearing process.  Effective 2011, NSP-Wisconsin began submitting a forward looking fuel cost plan that allows for deferral of fuel cost under-collection or over-collection in excess of a two percent annual tolerance band, for future rate recovery or refund.  Fuel costs are subject to PSCW hearings and approval, and other requirements.
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 that is required to be decommissioned early by a regulator is reclassified as plant to be retired.
	Property, plant and equipment is tested for impairment when it is determined that the carrying value of the assets may not be recoverable. Recently completed property, plant and equipment that is disallowed for cost recovery is expensed in the current period. For investments in property, plant and equipment that are 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 on abandonment 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 and semi-actuarial life studies are performed on a periodic basis and submitted to the state and federal commissions for review.  Upon acceptance by the various commissions, the resulting lives and net salvage rates are used to calculate depreciation.  Depreciation expense, expressed as a percentage of average depreciable property, was approximately 3.5, 3.5 and 3.6 percent for the years ended Dec. 31, 2013, 2012 and 2011, 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 other nonoperating income (for equity capital) and interest charges (for debt capital). AFUDC amounts capitalized are included in NSP-Wisconsin’s rate base for establishing utility service rates.
	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.
Asset Retirement Obligations	'
	AROs — NSP-Wisconsin records future plant removal obligations as a liability at fair value with a corresponding increase to the carrying values of the related long-lived assets in accordance with the applicable accounting guidance.  This liability will be increased over time by applying the effective interest method of accretion to the liability and the capitalized costs will be depreciated over the useful life of the related long-lived assets.  The recording of the obligation for regulated operations has no income statement impact due to the deferral of the amounts through the establishment of a regulatory asset and recovery in rates.
	NSP-Wisconsin also recovers currently in rates certain future plant removal costs in addition to AROs and related capitalized costs, and a regulatory liability is recognized for such future expenditures.  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. Investment tax credits are deferred and their benefits amortized over the book depreciable lives of the related 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 net asset values.  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.
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.  The estimates are 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 extend indefinitely 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 are classified as a regulatory liability.
	See Note 11 for further discussion of environmental costs.
Benefit Plans and Other Postretirement Benefits	'
	Benefit Plans and Other Postretirement Benefits — NSP-Wisconsin maintains pension and postretirement benefit plans for eligible employees.  Recognizing the cost of providing benefits and measuring the projected benefit obligation of these plans under applicable accounting guidance requires management to make various assumptions and estimates.
	Based on regulatory recovery mechanisms, certain unrecognized actuarial gains and losses and unrecognized prior service costs or credits are recorded as regulatory assets and liabilities, rather than OCI.
	See Note 7 for further discussion of benefit plans and other postretirement benefits.
Guarantees	'
	Guarantees — NSP-Wisconsin recognizes, upon issuance or modification of a guarantee, a liability for the fair market value of the obligation that has been assumed in issuing the guarantee.  This liability includes consideration of specific triggering events and other conditions which may modify the ongoing obligation to perform under the guarantee.
	The obligation recognized is reduced over the term of the guarantee as NSP-Wisconsin is released from risk under the guarantee.  See Note 11 for specific details of issued guarantees.
Subsequent Events	'
	Subsequent Events — Management has evaluated the impact of events occurring after Dec. 31, 2013 up to the date of issuance of these consolidated financial statements.  These statements contain all necessary adjustments and disclosures resulting from that evaluation.

Selected_Balance_Sheet_Data_Ta

Selected Balance Sheet Data (Tables)	12 Months Ended
	Dec. 31, 2013
Balance Sheet Related Disclosures [Abstract]	'
Accounts Receivable, Net	'
	(Thousands of Dollars)		Dec. 31, 2013			Dec. 31, 2012
	Accounts receivable, net (a)
	Accounts receivable		$	64,180		$	55,039
	Less allowance for bad debts		(4,911		)	(4,333		)
			$	59,269		$	50,706
	(a)	Accounts receivable, net includes $1,595 and $586 due from affiliates as of Dec. 31, 2013 and 2012, respectively.
Inventories	'
	(Thousands of Dollars)		Dec. 31, 2013			Dec. 31, 2012
	Inventories
	Materials and supplies		$	6,437		$	6,172
	Fuel		5,915			6,664
	Natural gas		9,123			6,849
			$	21,475		$	19,685
Property, Plant and Equipment, Net	'
	(Thousands of Dollars)		Dec. 31, 2013			Dec. 31, 2012
	Property, plant and equipment, net
	Electric plant		$	1,913,354		$	1,795,239
	Natural gas plant		236,047			224,625
	Common and other property		112,886			111,319
	CWIP		127,954			62,629
	Total property, plant and equipment		2,390,241			2,193,812
	Less accumulated depreciation		(947,462		)	(895,576		)
			$	1,442,779		$	1,298,236

Borrowings_and_Other_Financing1

Borrowings and Other Financing Instruments (Tables)	12 Months Ended
	Dec. 31, 2013
Borrowings and Other Financing Instruments [Abstract]	'
Committed Credit Facility Available	'
	At Dec. 31, 2013, NSP-Wisconsin had the following committed credit facility available (in millions of dollars):
	Credit Facility (a)				Drawn (b)				Available
	$	150			$	68			$	82
	(a)	Credit facility expires in July 2017.
	(b)	Includes outstanding commercial paper.
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, 2013
	Borrowing limit		$	150
	Amount outstanding at period end		68
	Average amount outstanding		41
	Maximum amount outstanding		71
	Weighted average interest rate, computed on a daily basis		0.3		%
	Weighted average interest rate at period end		0.27
	(Amounts in Millions, Except Interest Rates)		Twelve Months Ended Dec. 31, 2013				Twelve Months Ended Dec. 31, 2012				Twelve Months Ended Dec. 31, 2011
	Borrowing limit		$	150			$	150			$	150
	Amount outstanding at period end		68				39				66
	Average amount outstanding		20				61				24
	Maximum amount outstanding		71				116				70
	Weighted average interest rate, computed on a daily basis		0.31		%		0.39		%		0.37		%
	Weighted average interest rate at period end		0.27				0.4				0.46
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, 2013				Dec. 31, 2012
	Notes payable to affiliates		$	0.5			$	0.6
	Weighted average interest rate		0.24		%		0.33		%

Joint_Ownership_of_Transmissio1

Joint Ownership of Transmission Facilities (Tables)	12 Months Ended
	Dec. 31, 2013
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, 2013:
	(Thousands of Dollars)	Plant in		Accumulated Depreciation		CWIP		Ownership %
		Service
	Electric Transmission:
	CapX2020 Transmission	$	13,337	$	4,659	$	30,199	77.9	%
	La Crosse, Wis. to Madison, Wis.	—		—		5,431		50
	Total NSP-Wisconsin	$	13,337	$	4,659	$	35,630

Income_Taxes_Tables

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2013
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, 2013				Dec. 31, 2012
	Unrecognized tax benefit — Permanent tax positions	$	0.1			$	0.1
	Unrecognized tax benefit — Temporary tax positions	1.4				1.2
	Total unrecognized tax benefit	$	1.5			$	1.3
	A reconciliation of the beginning and ending amount of unrecognized tax benefit is as follows:
	(Millions of Dollars)	2013				2012				2011
	Balance at Jan. 1	$	1.3			$	1.5			$	1.9
	Additions based on tax positions related to the current year	0.7				0.5				0.6
	Reductions based on tax positions related to the current year	—				(0.2		)		(0.1		)
	Additions for tax positions of prior years	0.5				0.3				0.7
	Reductions for tax positions of prior years	—				(0.8		)		(0.3		)
	Settlements with taxing authorities	(1.0		)		—				(1.2		)
	Lapse of applicable statutes of limitations	—				—				(0.1		)
	Balance at Dec. 31	$	1.5			$	1.3			$	1.5
Tax Benefits Associated with NOL and Tax Credit Carryforwards	'
	The unrecognized tax benefit amounts were reduced by the tax benefits associated with NOL and tax credit carryforwards.  The amounts of tax benefits associated with NOL and tax credit carryforwards are as follows:
	(Millions of Dollars)	Dec. 31, 2013				Dec. 31, 2012
	NOL and tax credit carryforwards	$	(0.4	)		$	(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)	2013			2012
	Federal NOL carryforward	46.8			44.3
	Federal tax credit carryforwards	4.4			8
	State NOL carryforward	6.3			3.4
Schedule of Effective Income Tax Rate Reconciliation	'
	Total income tax expense from operations differs from the amount computed by applying the statutory federal income tax rate to income before income tax expense. The following reconciles such differences for the years ending Dec. 31:
		2013			2012			2011
	Federal statutory rate	35	%		35	%		35	%
	Increases (decreases) in tax from:
	State income taxes, net of federal income tax benefit	5			3.4			4.4
	Tax credits recognized	(0.9	)		(0.9	)		(0.9	)
	Regulatory differences — utility plant items	(0.9	)		(0.3	)		0.5
	Change in unrecognized tax benefits	—			0.1			(0.2	)
	Other, net	(0.2	)		(0.1	)		0.9
	Effective income tax rate	38	%		37.2	%		39.7	%
Schedule of Components of Income Tax Expense (Benefit)	'
	The components of income tax expense for the years ending Dec. 31 were:
	(Thousands of Dollars)	2013				2012				2011
	Current federal tax expense (benefit)	$	5,902			$	930			$	(1,540	)
	Current state tax expense	4,628				2,216				1,573
	Current change in unrecognized tax expense (benefit)	754				(69		)		(1,418		)
	Deferred federal tax expense	23,794				25,089				30,251
	Deferred state tax expense	2,720				1,890				4,105
	Deferred change in unrecognized tax (benefit) expense	(725		)		128				1,254
	Deferred investment tax credits	(664		)		(626		)		(611		)
	Total income tax expense	$	36,409			$	29,558			$	33,614
	The components of deferred income tax expense for the years ending Dec. 31 were:
	(Thousands of Dollars)	2013				2012				2011
	Deferred tax expense excluding items below	$	27,516			$	27,995			$	34,017
	Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities	(1,676		)		(837		)		1,644
	Tax expense allocated to other comprehensive income	(51		)		(51		)		(51		)
	Deferred tax expense	$	25,789			$	27,107			$	35,610
Schedule of Deferred Tax Assets and Liabilities	'
	The components of the net deferred tax liability (current and noncurrent) at Dec. 31 were as follows:
	(Thousands of Dollars)	2013				2012
	Deferred tax liabilities:
	Difference between book and tax bases of property	$	287,121			$	265,202
	Regulatory assets	57,296				52,898
	Employee benefits	16,953				16,862
	Other	10,193				10,535
	Total deferred tax liabilities	$	371,563			$	345,497
	Deferred tax assets:
	Environmental remediation	43,501				43,344
	NOL carryforward	17,384				17,588
	Regulatory liabilities	6,205				5,927
	Deferred investment tax credits	5,976				5,766
	Tax credit carryforward	4,440				8,011
	Other	3,871				2,191
	Total deferred tax assets	$	81,377			$	82,827
	Net deferred tax liability	$	290,186			$	262,670

Benefit_Plans_and_Other_Postre1

Benefit Plans and Other Postretirement Benefits (Tables)	12 Months Ended
	Dec. 31, 2013
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				Gross Projected				Expected Medicare			Net Projected
			Benefit Payments				Postretirement				Part D Subsidies			Postretirement
							Health Care							Health Care
							Benefit Payments							Benefit Payments
	2014		$	21,677			$	1,491			$	27		$	1,464
	2015		14,257				1,459				25			1,434
	2016		13,420				1,444				24			1,420
	2017		13,851				1,384				20			1,364
	2018		12,983				1,357				18			1,339
	2019-2023		64,935				6,229				82			6,147
Contributions to Multiemployer Plans	'
	Contributions to multiemployer plans were as follows for the years ended Dec. 31, 2013, 2012 and 2011.  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)		2013				2012				2011
	Multiemployer plan contributions:
	Pension		$	130			$	163			$	169
	Total		$	130			$	163			$	169
Pension Plans	'
Benefit Plans and Other Postretirement Benefits [Abstract]	'
Target Asset Allocations and Plan Assets Measured at Fair Value	'
	The following table presents the target pension asset allocations for NSP-Wisconsin:
			2013			2012
	Domestic and international equity securities		31	%		29	%
	Long-duration fixed income and interest rate swap securities		29			30
	Short-to-intermediate term fixed income securities		16			12
	Alternative investments		22			27
	Cash		2			2
	Total		100	%		100	%
	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, 2013 and 2012:
			Dec. 31, 2013
	(Thousands of Dollars)		Level 1				Level 2				Level 3			Total
	Cash equivalents		$	4,332			$	—			$	—		$	4,332
	Derivatives		—				937				—			937
	Government securities		—				6,711				—			6,711
	Corporate bonds		—				24,955				—			24,955
	Asset-backed securities		—				307				—			307
	Mortgage-backed securities		—				684				—			684
	Common stock		4,533				—				—			4,533
	Private equity investments		—				—				7,502			7,502
	Commingled funds		—				84,364				—			84,364
	Real estate		—				—				2,299			2,299
	Securities lending collateral obligation and other		—				311				—			311
	Total		$	8,865			$	118,269			$	9,801		$	136,935
			Dec. 31, 2012
	(Thousands of Dollars)		Level 1				Level 2				Level 3			Total
	Cash equivalents		$	7,956			$	—			$	—		$	7,956
	Derivatives		—				390				—			390
	Government securities		—				9,406				—			9,406
	Corporate bonds		—				25,046				—			25,046
	Asset-backed securities		—				—				749			749
	Mortgage-backed securities		—				—				2,128			2,128
	Common stock		3,977				—				—			3,977
	Private equity investments		—				—				8,545			8,545
	Commingled funds		—				76,398				—			76,398
	Real estate		—				—				3,472			3,472
	Securities lending collateral obligation and other		—				(1,521		)		—			(1,521		)
	Total		$	11,933			$	109,719			$	14,894		$	136,546
Changes in Level 3 Plan Assets	'
	The following tables present the changes in NSP-Wisconsin’s Level 3 pension plan assets for the years ended Dec. 31, 2013, 2012 and 2011:
	(Thousands of Dollars)		Jan. 1, 2013				Net Realized				Net Unrealized			Purchases,			Transfer Out			Dec. 31, 2013
							Gains (Losses)				Gains (Losses)			Issuances and			of Level 3 (a)
														Settlements, Net
	Asset-backed securities		$	749			$	—			$	—		$	—		$	(749	)	$	—
	Mortgage-backed securities		2,128				—				—			—			(2,128		)	—
	Private equity investments		8,545				1,083				(1,960		)	(166		)	—			7,502
	Real estate		3,472				(129		)		247			450			(1,741		)	2,299
	Total		$	14,894			$	954			$	(1,713	)	$	284		$	(4,618	)	$	9,801
	(a)	Transfers out of Level 3 into Level 2 were principally due to diminished use of unobservable inputs that were previously significant to these fair value measurements and were subsequently sold during 2013.
	(Thousands of Dollars)		Jan. 1, 2012				Net Realized				Net Unrealized			Purchases,			Transfers Out of Level 3			Dec. 31, 2012
							Gains (Losses)				Gains (Losses)			Issuances and
														Settlements, Net
	Asset-backed securities		$	1,578			$	197			$	(273	)	$	(753	)	$	—		$	749
	Mortgage-backed securities		3,781				93				(112		)	(1,634		)	—			2,128
	Private equity investments		8,440				945				(1,197		)	357			—			8,545
	Real estate		2,008				1				328			1,135			—			3,472
	Total		$	15,807			$	1,236			$	(1,254	)	$	(895	)	$	—		$	14,894
	(Thousands of Dollars)		Jan. 1, 2011				Net Realized				Net Unrealized			Purchases,			Transfers Out of Level 3			Dec. 31, 2011
							Gains (Losses)				Gains (Losses)			Issuances and
														Settlements, Net
	Asset-backed securities		$	1,367			$	121			$	(125	)	$	215		$	—		$	1,578
	Mortgage-backed securities		5,984				55				(295		)	(1,963		)	—			3,781
	Private equity investments		6,704				210				648			878			—			8,440
	Real estate		3,746				(34		)		1,002			(2,706		)	—			2,008
	Total		$	17,801			$	352			$	1,230		$	(3,576	)	$	—		$	15,807
Change in Projected Benefit Obligation	'
	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)		2013				2012
	Accumulated Benefit Obligation at Dec. 31		$	153,894			$	169,939
	Change in Projected Benefit Obligation:
	Obligation at Jan. 1		$	179,995			$	159,766
	Service cost		5,682				4,568
	Interest cost		6,924				7,765
	Plan amendments		(1,109		)		216
	Actuarial (gain) loss		(11,097		)		21,083
	Benefit payments		(16,465		)		(13,403		)
	Obligation at Dec. 31		$	163,930			$	179,995
Change in Fair Value of Plan Assets	'
	(Thousands of Dollars)		2013				2012
	Change in Fair Value of Plan Assets:
	Fair value of plan assets at Jan. 1		$	136,546			$	121,348
	Actual return on plan assets		5,525				16,079
	Employer contributions		11,329				12,522
	Benefit payments		(16,465		)		(13,403		)
	Fair value of plan assets at Dec. 31		$	136,935			$	136,546
Funded Status of Plans	'
	(Thousands of Dollars)		2013				2012
	Funded Status of Plans at Dec. 31:
	Funded status (a)		$	(26,995	)		$	(43,449	)
	(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)		2013				2012
	Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:
	Net loss		$	84,773			$	99,338
	Prior service cost		778				2,290
	Total		$	85,551			$	101,628
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)		2013				2012
	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		$	7,631			$	6,895
	Noncurrent regulatory assets		77,920				94,733
	Total		$	85,551			$	101,628
Schedule of Assumptions Used	'
			2013			2012			2011
	Significant Assumptions Used to Measure Costs:
	Discount rate		4	%		5	%		5.5	%
	Expected average long-term increase in compensation level		3.75			4			4
	Expected average long-term rate of return on assets		7.25			7.5			8
	Measurement date		Dec. 31, 2013		Dec. 31, 2012
			2013			2012
	Significant Assumptions Used to Measure Benefit Obligations:
	Discount rate for year-end valuation		4.75	%		4	%
	Expected average long-term increase in compensation level		3.75			3.75
	Mortality table		RP 2000			RP 2000
Components of Net Periodic Benefit Costs	'
	Benefit Costs — The components of NSP-Wisconsin’s net periodic pension cost were:
	(Thousands of Dollars)		2013				2012				2011
	Service cost		$	5,682			$	4,568			$	4,271
	Interest cost		6,924				7,765				8,031
	Expected return on plan assets		(9,995		)		(10,489		)		(11,484		)
	Amortization of prior service cost		417				1,771				1,895
	Amortization of net loss		7,924				6,004				4,070
	Net periodic pension cost		$	10,952			$	9,619			$	6,783
Postretirement Benefit Plan	'
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 postretirement benefit plan assets that are measured at fair value as of Dec. 31, 2013 and 2012:
			Dec. 31, 2013
	(Thousands of Dollars)		Level 1				Level 2				Level 3			Total
	Cash equivalents		$	31			$	—			$	—		$	31
	Derivatives		—				(2		)		—			(2		)
	Government securities		—				89				—			89
	Insurance contracts		—				80				—			80
	Corporate bonds		—				79				—			79
	Asset-backed securities		—				5				—			5
	Mortgage-backed securities		—				37				—			37
	Commingled funds		—				452				—			452
	Other		—				(25		)		—			(25		)
	Total		$	31			$	715			$	—		$	746
			Dec. 31, 2012
	(Thousands of Dollars)		Level 1				Level 2				Level 3			Total
	Cash equivalents		$	123			$	—			$	—		$	123
	Government securities		—				99				—			99
	Insurance contracts		—				67				—			67
	Corporate bonds		—				59				—			59
	Asset-backed securities		—				—				1			1
	Mortgage-backed securities		—				—				54			54
	Commingled funds		—				307				—			307
	Other		—				(63		)		—			(63		)
	Total		$	123			$	469			$	55		$	647
Changes in Level 3 Plan Assets	'
	The following tables present the changes in NSP-Wisconsin’s Level 3 postretirement benefit plan assets for the years ended Dec. 31, 2013, 2012 and 2011:
	(Thousands of Dollars)		Jan. 1, 2013				Net Realized				Net Unrealized			Purchases,			Transfers Out of Level 3 (a)			Dec. 31, 2013
							Gains (Losses)				Gains (Losses)			Issuances and
														Settlements, Net
	Asset-backed securities		$	1			$	—			$	—		$	—		$	(1	)	$	—
	Mortgage-backed securities		54				—				—			—			(54		)	—
	Total		$	55			$	—			$	—		$	—		$	(55	)	$	—
	(a)	Transfers out of Level 3 into Level 2 were principally due to diminished use of unobservable inputs that were previously significant to these fair value measurements and were subsequently sold during 2013.
	(Thousands of Dollars)		Jan. 1, 2012				Net Realized				Net Unrealized			Purchases,			Transfers Out of Level 3			Dec. 31, 2012
							Gains (Losses)				Gains (Losses)			Issuances and
														Settlements, Net
	Asset-backed securities		$	14			$	—			$	3		$	(16	)	$	—		$	1
	Mortgage-backed securities		48				(1		)		6			1			—			54
	Total		$	62			$	(1	)		$	9		$	(15	)	$	—		$	55
	(Thousands of Dollars)		Jan. 1, 2011				Net Realized				Net Unrealized			Purchases,			Transfers Out of Level 3			Dec. 31, 2011
							Gains (Losses)				Gains (Losses)			Issuances and
														Settlements, Net
	Asset-backed securities		$	6			$	—			$	(2	)	$	10		$	—		$	14
	Mortgage-backed securities		45				(3		)		6			—			—			48
	Total		$	51			$	(3	)		$	4		$	10		$	—		$	62
Change in Projected Benefit Obligation	'
	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)		2013				2012
	Change in Projected Benefit Obligation:
	Obligation at Jan. 1		$	19,432			$	22,127
	Service cost		25				20
	Interest cost		760				1,075
	Medicare subsidy reimbursements		31				189
	Plan amendments		—				(3,440		)
	Plan participants’ contributions		621				893
	Actuarial (gain) loss		(1,724		)		1,486
	Benefit payments		(1,992		)		(2,918		)
	Obligation at Dec. 31		$	17,153			$	19,432
Change in Fair Value of Plan Assets	'
	(Thousands of Dollars)		2013				2012
	Change in Fair Value of Plan Assets:
	Fair value of plan assets at Jan. 1		$	647			$	746
	Actual return on plan assets		(13		)		3
	Plan participants’ contributions		621				893
	Employer contributions		1,483				1,923
	Benefit payments		(1,992		)		(2,918		)
	Fair value of plan assets at Dec. 31		$	746			$	647
Funded Status of Plans	'
	(Thousands of Dollars)		2013				2012
	Funded Status of Plans at Dec. 31:
	Funded status		$	(16,407	)		$	(18,785	)
	Current liabilities		(718		)		(943		)
	Noncurrent liabilities		(15,689		)		(17,842		)
	Net postretirement amounts recognized on consolidated balance sheets		$	(16,407	)		$	(18,785	)
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost	'
	(Thousands of Dollars)		2013				2012
	Amounts Not Yet Recognized as Components of Net Periodic Cost:
	Net loss		$	11,098			$	13,730
	Prior service credit		(3,187		)		(3,538		)
	Transition obligation		—				1
	Total		$	7,911			$	10,193
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)		2013				2012
	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		$	570			$	433
	Noncurrent regulatory assets		7,341				9,760
	Total		$	7,911			$	10,193
Schedule of Assumptions Used	'
	Measurement date		Dec. 31, 2013		Dec. 31, 2012
			2013			2012
	Significant Assumptions Used to Measure Benefit Obligations:
	Discount rate for year-end valuation		4.82	%		4.1	%
	Mortality table		RP 2000			RP 2000
	Health care costs trend rate — initial		7	%		7.5	%
			2013			2012			2011
	Significant Assumptions Used to Measure Costs:
	Discount rate		4.1	%		5	%		5.5	%
	Expected average long-term rate of return on assets		7.11			6.75			7.5
Components of Net Periodic Benefit Costs	'
	Benefit Costs — The components of NSP-Wisconsin’s net periodic postretirement benefit cost were:
	(Thousands of Dollars)		2013				2012				2011
	Service cost		$	25			$	20			$	17
	Interest cost		760				1,075				1,144
	Expected return on plan assets		(42		)		(50		)		(74		)
	Amortization of transition obligation		1				171				171
	Amortization of prior service credit		(351		)		(14		)		(14		)
	Amortization of net loss		963				486				366
	Net periodic postretirement benefit cost		$	1,356			$	1,688			$	1,610
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		$	1,773			$	(1,486	)
	Service and interest components		78				(61		)

Other_Income_Net_Tables

Other Income, Net (Tables)	12 Months Ended
	Dec. 31, 2013
Other Income and Expenses [Abstract]	'
Other Income, Net	'
	Other income, net for the years ended Dec. 31 consisted of the following:
	(Thousands of Dollars)	2013			2012			2011
	Interest income	$	538		$	736		$	324
	Other nonoperating income	152			129			67
	Insurance policy expense	(427		)	(389		)	(283		)
	Other nonoperating expense	(10		)	—			(10		)
	Other income, net	$	253		$	476		$	98

Fair_Value_of_Financial_Assets1

Fair Value of Financial Assets and Liabilities (Tables)	12 Months Ended
	Dec. 31, 2013
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, 2013 and 2012:
	(Amounts in Thousands) (a)(b)		Dec. 31, 2013			Dec. 31, 2012
	MMBtu of natural gas		987			53
	(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)		2013				2012			2011
	Accumulated other comprehensive loss related to cash flow hedges at Jan. 1		$	(437	)		$	(514	)	$	(590	)
	After-tax net realized losses on derivative transactions reclassified into earnings		76				77			76
	Accumulated other comprehensive loss related to cash flow hedges at Dec. 31		$	(361	)		$	(437	)	$	(514	)
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, 2013
			Fair Value
	(Thousands of Dollars)		Level 1				Level 2			Level 3			Fair Value		Counterparty		Total (b)
													Total		Netting (a)
	Current derivative assets
	Natural gas commodity		$	—			$	580		$	—		$	580	$	—	$	580
			Dec. 31, 2012
			Fair Value
	(Thousands of Dollars)		Level 1				Level 2			Level 3			Fair Value		Counterparty		Total (c)
													Total		Netting (a)
	Current derivative liabilities
	Natural gas commodity		$	—			$	11		$	—		$	11	$	—	$	11
	(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, 2013 and 2012.  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 other current assets balance of $5.1 million at Dec. 31, 2013 in the consolidated balance sheets.
	(c)	Included in other current liabilities balance of $11.0 million at Dec. 31, 2012 in the consolidated balance sheets.
Carrying Amount and Fair Value of Long-term Debt	'
	As of Dec. 31, 2013 and 2012, other financial instruments for which the carrying amount did not equal fair value were as follows:
			2013							2012
	(Thousands of Dollars)		Carrying Amount				Fair Value			Carrying Amount			Fair Value
	Long-term debt, including current portion		$	468,597			$	518,269		$	468,563		$	576,353

Commitments_and_Contingencies_

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2013
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, 2013 are as follows:
	(Millions of dollars)		Coal		Natural gas		Natural gas
					supply		storage and
							transportation
	2014		$	6.2	$	13.4	$	11.9
	2015		1.3		0.3		11.6
	2016		0.7		0.3		11.7
	2017		0.7		0.2		9.5
	2018		0.7		—		4.4
	Thereafter		4.1		—		18.9
	Total (a)		$	13.7	$	14.2	$	68
	(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)
	2014		$	0.8
	2015		0.8
	2016		0.8
	2017		0.9
	2018		0.9
	Thereafter		8.8
	Total		$	13
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, 2013		Dec. 31, 2012
	Current assets		$	223	$	357
	Property, plant and equipment, net		2,427		2,599
	Other noncurrent assets		112		105
	Total assets		$	2,762	$	3,061
	Current liabilities		$	233	$	1,388
	Mortgages and other long-term debt payable		1,687		617
	Other noncurrent liabilities		42		39
	Total liabilities		$	1,962	$	2,044
Guarantee Issued and Outstanding	'
	The following table presents the guarantee issued and outstanding for NSP-Wisconsin:
	(Millions of Dollars)		Guarantee		Current		Term or		Triggering
			Amount		Exposure		Expiration Date		Event
									Requiring
									Performance
	Guarantee of customer loans for the Farm Rewiring Program		$	1	$	0.3	2017		(a)
	(a)	The debtor becomes the subject of bankruptcy or other insolvency proceedings.
Asset Retirement Obligations	'
	A reconciliation of NSP-Wisconsin’s AROs is shown in the tables below for the years ended Dec. 31, 2013 and 2012, respectively:
	(Thousands of Dollars)		Beginning Balance		Liabilities Recognized		Accretion			Revisions to			Ending Balance
			Jan. 1, 2013							Prior Estimates			Dec. 31, 2013 (a)
	Electric plant
	Steam production asbestos		$	1,962	$	—	$	43		$	—		$	2,005
	Steam and other production ash containment		125		—		12			224			361
	Electric distribution		13		—		1			22			36
	Other		826		—		20			(557		)	289
	Natural gas plant
	Gas transmission and distribution		75		—		5			(5		)	75
	Common and other property
	Common miscellaneous		35		—		3			49			87
	Total liability (b)		$	3,036	$	—	$	84		$	(267	)	$	2,853
	(Thousands of Dollars)		Beginning Balance		Liabilities Recognized		Accretion			Revisions to			Ending Balance
			Jan. 1, 2012							Prior Estimates			Dec. 31, 2012 (a)
	Electric plant
	Steam production asbestos		$	—	$	1,962	$	—		$	—		$	1,962
	Steam and other production ash containment		120		—		5			—			125
	Electric distribution		13		—		—			—			13
	Other		186		—		7			633			826
	Natural gas plant
	Gas transmission and distribution		71		—		4			—			75
	Common and other property
	Common miscellaneous		34		—		1			—			35
	Total liability (b)		$	424	$	1,962	$	17		$	633		$	3,036
	(a)	There were no ARO liabilities settled during the 12 months ended Dec. 31, 2013 or 2012.
	(b)	Included in the other long-term liabilities balance in the consolidated balance sheets.

Regulatory_Assets_and_Liabilit1

Regulatory Assets and Liabilities (Tables)	12 Months Ended
	Dec. 31, 2013
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, 2013 and 2012 are:
	(Thousands of Dollars)		See Note(s)	Remaining	Dec. 31, 2013				Dec. 31, 2012
				Amortization Period
	Regulatory Assets				Current		Noncurrent		Current		Noncurrent
	Environmental remediation costs		1, 11	Various	$	4,376	$	117,684	$	2,521	$	109,162
	Pension and retiree medical obligations (a)		7	Various	8,202		85,220		7,328		104,426
	Recoverable deferred taxes on AFUDC recorded in plant		1	Plant lives	—		12,679		—		10,458
	Losses on reacquired debt		4	Term of related debt	801		5,737		800		6,538
	State commission adjustments		1	Plant lives	410		9,355		339		7,533
	Conservation programs		1	Less than one year	404		—		691		—
	Deferred income tax adjustment		1, 6	Typically plant lives	—		1,763		—		1,974
	Recoverable purchased natural gas and electric energy costs			Less than one year	673		—		358		—
	Other			Various	—		755		11		368
	Total regulatory assets				$	14,866	$	233,193	$	12,048	$	240,459
	(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, 2013 and 2012 are:
	(Thousands of Dollars)		See Note(s)	Remaining	Dec. 31, 2013				Dec. 31, 2012
				Amortization Period
	Regulatory Liabilities				Current		Noncurrent		Current		Noncurrent
	Plant removal costs		11	Plant lives	$	—	$	116,293	$	—	$	113,949
	DOE settlement		11	Less than one year	6,814		—		5,628		—
	Investment tax credit deferrals		1, 6	Various	—		9,976		—		9,626
	Conservation programs		1	Less than one year	1,187		—		73		—
	Deferred electric production and natural gas costs		1	Less than one year	1,542		—		134		—
	Other			Various	174		155		251		171
	Total regulatory liabilities				$	9,717	$	126,424	$	6,086	$	123,746

Other_Comprehensive_Income_Tab

Other Comprehensive Income (Tables)	12 Months Ended
	Dec. 31, 2013
Stockholders' Equity Note [Abstract]	'
Changes in Accumulated Other Comprehensive Loss, Net of Tax	'
	Changes in accumulated other comprehensive loss, net of tax, for the year ended Dec. 31, 2013 were as follows:
	(Thousands of Dollars)		Gains and
			Losses on Cash
			Flow Hedges
	Accumulated other comprehensive loss at Jan. 1		$	(437	)
	Losses reclassified from net accumulated other comprehensive loss		76
	Net current period OCI		76
	Accumulated other comprehensive loss at Dec. 31		$	(361	)
Reclassifications out of Accumulated Other Comprehensive Loss	'
	Reclassifications from accumulated other comprehensive loss for the year ended Dec. 31, 2013 were as follows:
	(Thousands of Dollars)		Amounts
			Reclassified from
			Accumulated Other
			Comprehensive Loss
	Losses on cash flow hedges:
	Interest rate derivatives		$	127		(a)
	Total, pre-tax		127
	Tax benefit		(51		)
	Total amounts reclassified, net of tax		$	76
	(a)	Included in interest charges.

Segments_and_Related_Informati1

Segments and Related Information (Tables)	12 Months Ended
	Dec. 31, 2013
Segment Reporting [Abstract]	'
Results from Continuing Operations by Reportable Segment	'
	(Thousands of Dollars)		Regulated		Regulated		All Other			Reconciling			Consolidated
			Electric		Natural Gas					Eliminations			Total
	2013
	Operating revenues (a)		$	789,168	$	132,867	$	1,003		$	—		$	923,038
	Intersegment revenues		350		1,967		—			(2,317		)	—
	Total revenues		$	789,518	$	134,834	$	1,003		$	(2,317	)	$	923,038
	Depreciation and amortization		$	64,237	$	12,485	$	175		$	—		$	76,897
	Interest charges and financing costs		22,966		2,749		101			—			25,816
	Income tax expense (benefit)		33,691		4,623		(1,905		)	—			36,409
	Net Income		51,334		6,501		1,633			—			59,468
	(Thousands of Dollars)		Regulated		Regulated		All Other			Reconciling			Consolidated
			Electric		Natural Gas					Eliminations			Total
	2012
	Operating revenues (a)		$	757,565	$	103,100	$	1,177		$	—		$	861,842
	Intersegment revenues		355		727		—			(1,082		)	—
	Total revenues		$	757,920	$	103,827	$	1,177		$	(1,082	)	$	861,842
	Depreciation and amortization		$	59,768	$	9,251	$	215		$	—		$	69,234
	Interest charges and financing costs		20,303		2,554		80			—			22,937
	Income tax expense		27,164		2,113		281			—			29,558
	Net Income		45,377		3,094		1,480			—			49,951
	(Thousands of Dollars)		Regulated		Regulated		All Other			Reconciling			Consolidated
			Electric		Natural Gas					Eliminations			Total
	2011
	Operating revenues (a)		$	755,136	$	119,447	$	1,207		$	—		$	875,790
	Intersegment revenues		405		1,581		—			(1,986		)	—
	Total revenues		$	755,541	$	121,028	$	1,207		$	(1,986	)	$	875,790
	Depreciation and amortization		$	58,800	$	9,599	$	175		$	—		$	68,574
	Interest charges and financing costs		21,181		2,675		137			—			23,993
	Income tax expense (benefit)		32,656		1,995		(1,037		)	—			33,614
	Net Income		47,093		2,964		949			—			51,006
	(a)	Operating revenues include $137 million, $125 million and $124 million of intercompany revenue for the years ended Dec. 31, 2013, 2012 and 2011, respectively. See Note 15 for further discussion of related party transactions by operating segment.

Related_Party_Transactions_Tab

Related Party Transactions (Tables)	12 Months Ended
	Dec. 31, 2013
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)	2013		2012		2011
	Operating revenues:
	Electric	$	136,917	$	125,344	$	124,334
	Operating expenses:
	Purchased power	416,173		405,016		399,649
	Transmission expense	42,460		44,942		40,870
	Natural gas purchased for resale	97		116		98
	Other operating expenses — paid to Xcel Energy Services Inc.	61,531		54,137		54,885
	Interest expense	22		22		48
	Accounts receivable and payable with affiliates at Dec. 31 were:
		2013				2012
	(Thousands of Dollars)	Accounts		Accounts		Accounts		Accounts
		Receivable		Payable		Receivable		Payable
	NSP-Minnesota	$	—	$	18,584	$	—	$	26,632
	PSCo	—		8		—		71
	SPS	26		—		—		4
	Other subsidiaries of Xcel Energy Inc.	1,569		6,394		586		4,849
		$	1,595	$	24,986	$	586	$	31,556

Summarized_Quarterly_Financial1

Summarized Quarterly Financial Data (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2013
Quarterly Financial Information Disclosure [Abstract]	'
Summarized Quarterly Financial Data (Unaudited)	'
		Quarter Ended
	(Thousands of Dollars)	March 31, 2013		June 30, 2013		Sept. 30, 2013		Dec. 31, 2013
	Operating revenues	$	241,415	$	210,175	$	231,060	$	240,388
	Operating income	37,401		22,466		40,769		16,545
	Net income	19,685		10,544		22,013		7,225
		Quarter Ended
	(Thousands of Dollars)	March 31, 2012		June 30, 2012		Sept. 30, 2012		Dec. 31, 2012
	Operating revenues	$	223,799	$	194,173	$	226,475	$	217,395
	Operating income	28,914		14,348		40,735		15,869
	Net income	14,878		5,742		22,200		7,131

Summary_of_Significant_Account2

Summary of Significant Accounting Policies (Details)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Revenue Recognition [Abstract]	'	'	'
Number of years between rate review processes (in years)	'2 years	'	'
Minimum annual tolerance band percentage for future rate recovery or refund of fuel costs	2.00%	'	'
Property, Plant and Equipment and Depreciation [Abstract]	'	'	'
Depreciation expense expressed as a percentage of average depreciable property (in hundredths)	3.50%	3.50%	3.60%
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 (in months)	'3 months	'	'

Selected_Balance_Sheet_Data_Ac

Selected Balance Sheet Data, Accounts Receivable (Details) (USD $)	Dec. 31, 2013		Dec. 31, 2012
In Thousands, unless otherwise specified
Accounts Receivable, Net	'		'
Accounts receivable	$64,180		$55,039
Less allowance for bad debts	-4,911		-4,333
Accounts receivable, net	59,269	[1]	50,706	[1]
Accounts receivable from affiliates, net	$1,595		$586
[1]	Accounts receivable, net includes $1,595 and $586 due from affiliates as of Dec. 31, 2013 and 2012, respectively.

Selected_Balance_Sheet_Data_In

Selected Balance Sheet Data, Inventory (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Public Utilities, Inventory [Line Items]	'	'
Inventories	$21,475	$19,685
Materials and supplies	'	'
Public Utilities, Inventory [Line Items]	'	'
Inventories	6,437	6,172
Fuel	'	'
Public Utilities, Inventory [Line Items]	'	'
Inventories	5,915	6,664
Natural gas	'	'
Public Utilities, Inventory [Line Items]	'	'
Inventories	$9,123	$6,849

Selected_Balance_Sheet_Data_Pr

Selected Balance Sheet Data, Property, Plant and Equipment (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Public Utility, Property, Plant and Equipment [Line Items]	'	'
Property, Plant and Equipment, Gross	$2,390,241	$2,193,812
Less accumulated depreciation	-947,462	-895,576
Property, plant and equipment, net	1,442,779	1,298,236
Electric plant	'	'
Public Utility, Property, Plant and Equipment [Line Items]	'	'
Property, Plant and Equipment, Gross	1,913,354	1,795,239
Natural gas plant	'	'
Public Utility, Property, Plant and Equipment [Line Items]	'	'
Property, Plant and Equipment, Gross	236,047	224,625
Common and other property	'	'
Public Utility, Property, Plant and Equipment [Line Items]	'	'
Property, Plant and Equipment, Gross	112,886	111,319
CWIP	'	'
Public Utility, Property, Plant and Equipment [Line Items]	'	'
Property, Plant and Equipment, Gross	$127,954	$62,629

Borrowings_and_Other_Financing2

Borrowings and Other Financing Instruments, Commercial Paper (Details) (USD $)	3 Months Ended	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Short-term Debt [Line Items]	'	'	'	'
Amount outstanding at period end	$68,000,000	$68,000,000	$39,000,000	'
Commercial Paper	'	'	'	'
Short-term Debt [Line Items]	'	'	'	'
Borrowing limit	150,000,000	150,000,000	150,000,000	150,000,000
Amount outstanding at period end	68,000,000	68,000,000	39,000,000	66,000,000
Average amount outstanding	41,000,000	20,000,000	61,000,000	24,000,000
Maximum amount outstanding	$71,000,000	$71,000,000	$116,000,000	$70,000,000
Weighted average interest rate, computed on a daily basis (in hundredths)	0.30%	0.31%	0.39%	0.37%
Weighted average interest rate at period end (in hundredths)	0.27%	0.27%	0.40%	0.46%

Borrowings_and_Other_Financing3

Borrowings and Other Financing Instruments, Letters of Credit (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Letters of Credit [Abstract]	'	'
Terms of letters of credit (in years)	'1 year	'
Letters of credit outstanding under credit facilities	$0	$0

Borrowings_and_Other_Financing4

Borrowings and Other Financing Instruments, Credit Facility (Details) (USD $)	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012
Line of Credit Facility [Line Items]	'		'
Credit agreement term (in years)	'5		'
Line of Credit Facility, Maximum Borrowing Capacity	$150,000,000	[1]	'
Term Of Each Additional Period Revolving Termination Date Can Be Extended Subject To Majority Bank Group Approval	'1 year		'
Line Of Credit Facility Maximum Debt To Total Capitalization Ratio Allowed	65.00%		'
Line Of Credit Facility Debt To Total Capitalization Ratio	47.00%		'
Line Of Credit Facility Minimum Threshhold Percentage Of Subsidiary Assets To Consolidated Assets Required To Initiate Cross Default Provisions	15.00%		'
Line of Credit Facility, Minimum Amount of Indebtedness in Default to Initiate Cross Default Provisions	75,000,000		'
Credit Facilities Drawn	68,000,000	[2]	'
Line of Credit Facility, Remaining Borrowing Capacity	82,000,000		'
Line of Credit Facility, Amount Outstanding	$0		$0
Line Of Credit Facility Minimum Borrowing Margin Based On Long Term Credit Ratings	0.88%		'
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	0.08%		'
Line Of Credit Facility Maximum Commitment Fees Calculated On Unused Portion Of Lines Of Credit	0.28%		'
[1]	Credit facility expires in July 2017.
[2]	Includes outstanding commercial paper.

Borrowings_and_Other_Financing5

Borrowings and Other Financing Instruments,Other Short-Term Borrowings (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Short-term Debt [Line Items]	'	'
Notes payable to affiliates	$470	$550
Notes Payable, Other Payables	'	'
Short-term Debt [Line Items]	'	'
Notes payable to affiliates	$500	$600
Weighted average interest rate at period end (in hundredths)	0.24%	0.33%

Borrowings_and_Other_Financing6

Borrowings and Other Financing Instruments Borrowings and Other Financing Instruments, Long-Term Borrowings and Other Financing Instruments (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012	Oct. 31, 2012	Dec. 31, 2013
In Millions, unless otherwise specified			Bonds [Member]	Bonds [Member]
			Series Due Oct. 1, 2042	Series Due Oct. 1, 2042
Debt Instrument [Line Items]	'	'	'	'
Debt Instrument, Face Amount	'	'	$100	'
Debt Instrument, Interest Rate, Stated Percentage	'	'	3.70%	3.70%
Debt Instrument, Maturity Date	'	'	1-Oct-42	1-Oct-42
Long-term Debt, Maturities, Repayments of Principal in Year Five	150	'	'	'
Deferred Finance Costs, Noncurrent, Net	3.5	3.6	'	'
Maximum annual dividends that can be paid if equity capitalization ratio condition is not met	31.2	'	'	'
Minimum calendar year average equity to total capitalization ratio authorized by state commission	52.50%	'	'	'
Calendar year average equity to total capitalization ratio	52.80%	'	'	'
Unrestricted Retained Earnings Per State Regulatory Commissions Dividend Restrictions	$17.10	'	'	'

Joint_Ownership_of_Transmissio2

Joint Ownership of Transmission Facilities (Details) (USD $)	Dec. 31, 2013
In Thousands, unless otherwise specified
Jointly Owned Utility Plant [Abstract]	'
Plant in service	$13,337
Accumulated depreciation	4,659
Construction work in progress	35,630
CapX2020 Transmission [Member] | Electric Transmission [Member]	'
Jointly Owned Utility Plant [Abstract]	'
Plant in service	13,337
Accumulated depreciation	4,659
Construction work in progress	30,199
Ownership % (in hundredths)	77.90%
La Crosse, Wis. to Madison, Wis. [Member] | Electric Transmission [Member]	'
Jointly Owned Utility Plant [Abstract]	'
Plant in service	0
Accumulated depreciation	0
Construction work in progress	$5,431
Ownership % (in hundredths)	50.00%

Income_Taxes_Details

Income Taxes (Details) (USD $)	12 Months Ended			1 Months Ended	3 Months Ended	12 Months Ended		3 Months Ended	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2013	Sep. 30, 2012	Dec. 31, 2013	Dec. 31, 2012	Mar. 31, 2013	Dec. 31, 2013	Dec. 31, 2012
				Internal Revenue Service (IRS)	Internal Revenue Service (IRS)	Internal Revenue Service (IRS)	Internal Revenue Service (IRS)	State and Local Jurisdiction	State and Local Jurisdiction	State and Local Jurisdiction
Tax Audits [Abstract]	'	'	'	'	'	'	'	'	'	'
Year(s) no longer subject to audit as statute of limitations has expired	'	'	'	'	'	'2008	'	'	'	'
Earliest year subject to examination	'	'	'	'	'	'2009	'	'	'2009	'
Year(s) under examination	'	'	'	'	'2010 and 2011	'	'	'2009 through 2011	'	'
Tax Adjustments, Settlements, and Unusual Provisions	'	'	'	$10,000,000	'	'	'	'	'	'
Operating Loss Carryforwards	'	'	'	46,800,000	'	46,800,000	44,300,000	'	6,300,000	3,400,000
Tax Credit Carryforward, Amount	'	'	'	4,400,000	'	4,400,000	8,000,000	'	'	'
Carryforward expiration date range, low	'	'	'	'	'	'2021	'	'	'2022	'
Carryforward expiration date range, high	'	'	'	'	'	'2033	'	'	'2031	'
Unrecognized Tax Benefits [Abstract]	'	'	'	'	'	'	'	'	'	'
Unrecognized tax benefit — Permanent tax positions	100,000	100,000	'	'	'	'	'	'	'	'
Unrecognized tax benefit — Temporary tax positions	1,400,000	1,200,000	'	'	'	'	'	'	'	'
Total unrecognized tax benefit	1,500,000	1,300,000	1,500,000	'	'	'	'	'	'	'
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]	'	'	'	'	'	'	'	'	'	'
Balance at Jan. 1	1,300,000	1,500,000	1,900,000	'	'	'	'	'	'	'
Unrecognized Tax Benefits, Increase Resulting from Current Period Tax Positions	700,000	500,000	600,000	'	'	'	'	'	'	'
Unrecognized Tax Benefits, Decrease Resulting from Current Period Tax Positions	0	-200,000	-100,000	'	'	'	'	'	'	'
Unrecognized Tax Benefits Increases Resulting From Prior Period Tax Positions	500,000	300,000	700,000	'	'	'	'	'	'	'
Unrecognized Tax Benefits Decreases Resulting From Prior Period Tax Positions	0	-800,000	-300,000	'	'	'	'	'	'	'
Unrecognized Tax Benefits, Decrease Resulting from Settlements with Taxing Authorities	-1,000,000	0	-1,200,000	'	'	'	'	'	'	'
Unrecognized Tax Benefits, Reduction Resulting from Lapse of Applicable Statute of Limitations	0	0	-100,000	'	'	'	'	'	'	'
Balance at Dec. 31	1,500,000	1,300,000	1,500,000	'	'	'	'	'	'	'
Tax Benefits Associated With NOL And Tax Credit Carryforwards [Abstract]	'	'	'	'	'	'	'	'	'	'
NOL and tax credit carryforwards	-400,000	-900,000	'	'	'	'	'	'	'	'
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	5.00%	3.40%	4.40%	'	'	'	'	'	'	'
Effective Income Tax Rate Reconciliation, Tax Credit, Percent	-0.90%	-0.90%	-0.90%	'	'	'	'	'	'	'
Effective Income Tax Rate Reconciliation Regulatory Differences Utility Plant Items	-0.90%	-0.30%	0.50%	'	'	'	'	'	'	'
Effective Income Tax Rate Reconciliation Change In Unrecognized Tax Benefits	0.00%	0.10%	-0.20%	'	'	'	'	'	'	'
Effective Income Tax Rate Reconciliation, Other Adjustments, Percent	-0.20%	-0.10%	0.90%	'	'	'	'	'	'	'
Effective Income Tax Rate Reconciliation, Percent	38.00%	37.20%	39.70%	'	'	'	'	'	'	'
Components of Income Tax Expense (Benefit), Continuing Operations [Abstract]	'	'	'	'	'	'	'	'	'	'
Current Federal Tax Expense (Benefit)	5,902,000	930,000	-1,540,000	'	'	'	'	'	'	'
Current State and Local Tax Expense (Benefit)	4,628,000	2,216,000	1,573,000	'	'	'	'	'	'	'
Current Change In Unrecognized Tax Expense (Benefit)	754,000	-69,000	-1,418,000	'	'	'	'	'	'	'
Deferred Federal Income Tax Expense (Benefit)	23,794,000	25,089,000	30,251,000	'	'	'	'	'	'	'
Deferred State and Local Income Tax Expense (Benefit)	2,720,000	1,890,000	4,105,000	'	'	'	'	'	'	'
Deferred Change In Unrecognized Tax Expense (Benefit)	-725,000	128,000	1,254,000	'	'	'	'	'	'	'
Deferred investment tax credits	-664,000	-626,000	-611,000	'	'	'	'	'	'	'
Income Tax Expense (Benefit)	36,409,000	29,558,000	33,614,000	'	'	'	'	'	'	'
Deferred Income Tax Expense (Benefit), Continuing Operations [Abstract]	'	'	'	'	'	'	'	'	'	'
Deferred tax expense (benefit) excluding selected items	27,516,000	27,995,000	34,017,000	'	'	'	'	'	'	'
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities	-1,676,000	-837,000	1,644,000	'	'	'	'	'	'	'
Other Comprehensive Income (Loss), Tax	-51,000	-51,000	-51,000	'	'	'	'	'	'	'
Deferred Income Tax Expense (Benefit)	25,789,000	27,107,000	35,610,000	'	'	'	'	'	'	'
Deferred Tax Liabilities, Gross [Abstract]	'	'	'	'	'	'	'	'	'	'
Deferred Tax Liabilities, Property, Plant and Equipment	287,121,000	265,202,000	'	'	'	'	'	'	'	'
Deferred Tax Liabilities, Regulatory Assets	57,296,000	52,898,000	'	'	'	'	'	'	'	'
Deferred Tax Assets, Tax Deferred Expense, Compensation and Benefits, Employee Benefits	16,953,000	16,862,000	'	'	'	'	'	'	'	'
Deferred Tax Liabilities, Other	10,193,000	10,535,000	'	'	'	'	'	'	'	'
Deferred Tax Liabilities, Net	371,563,000	345,497,000	'	'	'	'	'	'	'	'
Deferred Tax Assets, Gross [Abstract]	'	'	'	'	'	'	'	'	'	'
Deferred Tax Assets Environmental Remediation	43,501,000	43,344,000	'	'	'	'	'	'	'	'
Deferred Tax Assets, Operating Loss Carryforwards	17,384,000	17,588,000	'	'	'	'	'	'	'	'
Deferred Tax Assets Regulatory Liabilities	6,205,000	5,927,000	'	'	'	'	'	'	'	'
Deferred Tax Assets Deferred Investment Tax Credits	5,976,000	5,766,000	'	'	'	'	'	'	'	'
Deferred Tax Assets Tax credit carryforward	4,440,000	8,011,000	'	'	'	'	'	'	'	'
Deferred Tax Assets, Other	3,871,000	2,191,000	'	'	'	'	'	'	'	'
Deferred Tax Assets, Net of Valuation Allowance	81,377,000	82,827,000	'	'	'	'	'	'	'	'
Deferred Tax Assets, Net	$290,186,000	$262,670,000	'	'	'	'	'	'	'	'

Benefit_Plans_and_Other_Postre2

Benefit Plans and Other Postretirement Benefits, Employees Represented by Local Labor Unions (Details)	Dec. 31, 2013
	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 (in hundredths)	70.00%
Number of bargaining employees receiving benefits under several collective bargaining agreements	399

Benefit_Plans_and_Other_Postre3

Benefit Plans and Other Postretirement Benefits Benefits Plans and Other Postretirement Benefits, Fair Value Hierarchy (Details)	12 Months Ended
	Dec. 31, 2013
Commingled funds | Minimum	'
Defined Benefit Plan Disclosure [Line Items]	'
Notice period for investment redemption (in days)	'1
Commingled funds | Maximum	'
Defined Benefit Plan Disclosure [Line Items]	'
Notice period for investment redemption (in days)	'90
Real estate funds | Minimum	'
Defined Benefit Plan Disclosure [Line Items]	'
Notice period for investment redemption (in days)	'45
Real estate funds | Maximum	'
Defined Benefit Plan Disclosure [Line Items]	'
Notice period for investment redemption (in days)	'90

Benefit_Plans_and_Other_Postre4

Benefit Plans and Other Postretirement Benefits, Pension Benefits (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Supplemental Executive Retirement Plan (SERP) and Nonqualified Pension Plan	'	'	'
Pension Benefits [Abstract]	'	'	'
Total benefit obligation	$600,000	$600,000	'
Pension Plans	'	'	'
Pension Benefits [Abstract]	'	'	'
Total benefit obligation	163,930,000	179,995,000	159,766,000
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 (in hundredths)	7.25%	7.50%	8.00%
Expected average long-term rate of return on assets for next fiscal year (in hundredths)	7.25%	'	'
Target Pension Asset Allocations [Abstract]	'	'	'
Target pension asset allocations (in hundredths)	100.00%	100.00%	'
Pension Plans | Domestic and international equity securities	'	'	'
Target Pension Asset Allocations [Abstract]	'	'	'
Target pension asset allocations (in hundredths)	31.00%	29.00%	'
Pension Plans | Long-duration fixed income and interest rate swap securities	'	'	'
Target Pension Asset Allocations [Abstract]	'	'	'
Target pension asset allocations (in hundredths)	29.00%	30.00%	'
Pension Plans | Short-to-intermediate fixed income securities	'	'	'
Target Pension Asset Allocations [Abstract]	'	'	'
Target pension asset allocations (in hundredths)	16.00%	12.00%	'
Pension Plans | Alternative investments	'	'	'
Target Pension Asset Allocations [Abstract]	'	'	'
Target pension asset allocations (in hundredths)	22.00%	27.00%	'
Pension Plans | Cash	'	'	'
Target Pension Asset Allocations [Abstract]	'	'	'
Target pension asset allocations (in hundredths)	2.00%	2.00%	'
Xcel Energy Inc. | Supplemental Executive Retirement Plan (SERP) and Nonqualified Pension Plan	'	'	'
Pension Benefits [Abstract]	'	'	'
Total benefit obligation	36,500,000	39,400,000	'
Net benefit cost recognized for financial reporting	$6,600,000	$15,600,000	'

Benefit_Plans_and_Other_Postre5

Benefit Plans and Other Postretirement Benefits, Fair Value of Pension Plan Assets (Details) (Pension Plans, USD $)	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
In Thousands, unless otherwise specified
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]	'	'	'	'
Fair value of plan assets	$136,935	$136,546	$121,348	'
Level 1	'	'	'	'
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]	'	'	'	'
Fair value of plan assets	8,865	11,933	'	'
Level 2	'	'	'	'
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]	'	'	'	'
Fair value of plan assets	118,269	109,719	'	'
Level 3	'	'	'	'
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]	'	'	'	'
Fair value of plan assets	9,801	14,894	15,807	17,801
Cash equivalents	'	'	'	'
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]	'	'	'	'
Fair value of plan assets	4,332	7,956	'	'
Cash equivalents | Level 1	'	'	'	'
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]	'	'	'	'
Fair value of plan assets	4,332	7,956	'	'
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	937	390	'	'
Derivatives | Level 1	'	'	'	'
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]	'	'	'	'
Fair value of plan assets	0	0	'	'
Derivatives | Level 2	'	'	'	'
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]	'	'	'	'
Fair value of plan assets	937	390	'	'
Derivatives | 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	6,711	9,406	'	'
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	6,711	9,406	'	'
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	'	'
Corporate bonds	'	'	'	'
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]	'	'	'	'
Fair value of plan assets	24,955	25,046	'	'
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	'	'
Corporate bonds | Level 2	'	'	'	'
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]	'	'	'	'
Fair value of plan assets	24,955	25,046	'	'
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	307	749	'	'
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	307	0	'	'
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	749	1,578	1,367
Mortgage-backed securities	'	'	'	'
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]	'	'	'	'
Fair value of plan assets	684	2,128	'	'
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	684	0	'	'
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	2,128	3,781	5,984
Common stock	'	'	'	'
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]	'	'	'	'
Fair value of plan assets	4,533	3,977	'	'
Common stock | Level 1	'	'	'	'
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]	'	'	'	'
Fair value of plan assets	4,533	3,977	'	'
Common stock | Level 2	'	'	'	'
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]	'	'	'	'
Fair value of plan assets	0	0	'	'
Common stock | 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	7,502	8,545	'	'
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	7,502	8,545	8,440	6,704
Commingled funds	'	'	'	'
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]	'	'	'	'
Fair value of plan assets	84,364	76,398	'	'
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	'	'
Commingled funds | Level 2	'	'	'	'
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]	'	'	'	'
Fair value of plan assets	84,364	76,398	'	'
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	'	'
Real estate	'	'	'	'
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]	'	'	'	'
Fair value of plan assets	2,299	3,472	'	'
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	2,299	3,472	2,008	3,746
Securities lending collateral obligation and other	'	'	'	'
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]	'	'	'	'
Fair value of plan assets	311	-1,521	'	'
Securities lending collateral obligation and 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	'	'
Securities lending collateral obligation and other | Level 2	'	'	'	'
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]	'	'	'	'
Fair value of plan assets	311	-1,521	'	'
Securities lending collateral obligation and other | Level 3	'	'	'	'
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]	'	'	'	'
Fair value of plan assets	$0	$0	'	'

Benefit_Plans_and_Other_Postre6

Benefit Plans and Other Postretirement Benefits, Changes in Level 3 Pension Plan Assets (Details) (Pension Plans, USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012	Dec. 31, 2011
Changes in Level 3 Plan Assets [Roll Forward]	'		'	'
Fair value of plan assets at Dec. 31	$136,935		$136,546	$121,348
Level 3	'		'	'
Changes in Level 3 Plan Assets [Roll Forward]	'		'	'
Fair value of plan assets at Jan. 1	14,894		15,807	17,801
Net realized gains (losses)	954		1,236	352
Net unrealized gains (losses)	-1,713		-1,254	1,230
Purchases, issuances and settlements, net	284		-895	-3,576
Transfers in (out) of Level 3	-4,618	[1]	0	0
Fair value of plan assets at Dec. 31	9,801		14,894	15,807
Asset-backed securities	'		'	'
Changes in Level 3 Plan Assets [Roll Forward]	'		'	'
Fair value of plan assets at Dec. 31	307		749	'
Asset-backed securities | Level 3	'		'	'
Changes in Level 3 Plan Assets [Roll Forward]	'		'	'
Fair value of plan assets at Jan. 1	749		1,578	1,367
Net realized gains (losses)	0		197	121
Net unrealized gains (losses)	0		-273	-125
Purchases, issuances and settlements, net	0		-753	215
Transfers in (out) of Level 3	-749	[1]	0	0
Fair value of plan assets at Dec. 31	0		749	1,578
Mortgage-backed securities	'		'	'
Changes in Level 3 Plan Assets [Roll Forward]	'		'	'
Fair value of plan assets at Dec. 31	684		2,128	'
Mortgage-backed securities | Level 3	'		'	'
Changes in Level 3 Plan Assets [Roll Forward]	'		'	'
Fair value of plan assets at Jan. 1	2,128		3,781	5,984
Net realized gains (losses)	0		93	55
Net unrealized gains (losses)	0		-112	-295
Purchases, issuances and settlements, net	0		-1,634	-1,963
Transfers in (out) of Level 3	-2,128	[1]	0	0
Fair value of plan assets at Dec. 31	0		2,128	3,781
Private equity investments	'		'	'
Changes in Level 3 Plan Assets [Roll Forward]	'		'	'
Fair value of plan assets at Dec. 31	7,502		8,545	'
Private equity investments | Level 3	'		'	'
Changes in Level 3 Plan Assets [Roll Forward]	'		'	'
Fair value of plan assets at Jan. 1	8,545		8,440	6,704
Net realized gains (losses)	1,083		945	210
Net unrealized gains (losses)	-1,960		-1,197	648
Purchases, issuances and settlements, net	-166		357	878
Transfers in (out) of Level 3	0	[1]	0	0
Fair value of plan assets at Dec. 31	7,502		8,545	8,440
Real estate	'		'	'
Changes in Level 3 Plan Assets [Roll Forward]	'		'	'
Fair value of plan assets at Dec. 31	2,299		3,472	'
Real estate | Level 3	'		'	'
Changes in Level 3 Plan Assets [Roll Forward]	'		'	'
Fair value of plan assets at Jan. 1	3,472		2,008	3,746
Net realized gains (losses)	-129		1	-34
Net unrealized gains (losses)	247		328	1,002
Purchases, issuances and settlements, net	450		1,135	-2,706
Transfers in (out) of Level 3	-1,741	[1]	0	0
Fair value of plan assets at Dec. 31	$2,299		$3,472	$2,008
[1]	Transfers out of Level 3 into Level 2 were principally due to diminished use of unobservable inputs that were previously significant to these fair value measurements and were subsequently sold during 2013.

Benefit_Plans_and_Other_Postre7

Benefit Plans and Other Postretirement Benefits, Pension Plan Benefit Obligations, Cash Flows and Benefit Costs (Details) (Pension Plans, USD $)	1 Months Ended	12 Months Ended
	Jan. 31, 2014	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Defined Benefit Plan Disclosure [Line Items]	'	'		'		'
Accumulated Benefit Obligation at Dec. 31	'	$153,894,000		$169,939,000		'
Change in Projected Benefit Obligation [Roll Forward]	'	'		'		'
Obligation at Jan. 1	163,930,000	179,995,000		159,766,000		'
Service cost	'	5,682,000		4,568,000		4,271,000
Interest cost	'	6,924,000		7,765,000		8,031,000
Plan amendments	'	-1,109,000		216,000		'
Actuarial (gain) loss	'	-11,097,000		21,083,000		'
Benefit payments	'	-16,465,000		-13,403,000		'
Obligation at Dec. 31	'	163,930,000		179,995,000		159,766,000
Change in Fair Value of Plan Assets [Roll Forward]	'	'		'		'
Fair value of plan assets at Jan. 1	136,935,000	136,546,000		121,348,000		'
Actual return (loss) on plan assets	'	5,525,000		16,079,000		'
Employer contributions	'	11,329,000		12,522,000		'
Benefit payments	'	-16,465,000		-13,403,000		'
Fair value of plan assets at Dec. 31	'	136,935,000		136,546,000		121,348,000
Funded Status of Plans at Dec. 31 [Abstract]	'	'		'		'
Funded status	'	-26,995,000	[1]	-43,449,000	[1]	'
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost [Abstract]	'	'		'		'
Net loss	'	84,773,000		99,338,000		'
Prior service (credit) cost	'	778,000		2,290,000		'
Total	'	85,551,000		101,628,000		'
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	'	7,631,000		6,895,000		'
Noncurrent regulatory assets	'	77,920,000		94,733,000		'
Total	'	85,551,000		101,628,000		'
Significant Assumptions Used to Measure Benefit Obligations [Abstract]	'	'		'		'
Measurement date	'	'12/31/2013		'12/31/2012		'
Discount rate for year-end valuation (in hundredths)	'	4.75%		4.00%		'
Expected average long-term increase in compensation level (in hundredths)	'	3.75%		3.75%		'
Mortality table	'	'RP 2000		'RP 2000		'
Cash Flows [Abstract]	'	'		'		'
Total contributions to Xcel Energy's pension plans during the period	8,000,000	11,300,000		12,500,000		6,400,000
Components of Net Periodic Benefit Cost (Credit) [Abstract]	'	'		'		'
Service cost	'	5,682,000		4,568,000		4,271,000
Interest cost	'	6,924,000		7,765,000		8,031,000
Expected return on plan assets	'	-9,995,000		-10,489,000		-11,484,000
Amortization of prior service cost (credit)	'	417,000		1,771,000		1,895,000
Amortization of net loss	'	7,924,000		6,004,000		4,070,000
Net periodic benefit cost	'	10,952,000		9,619,000		6,783,000
Significant Assumptions Used to Measure Costs [Abstract]	'	'		'		'
Discount rate (in hundredths)	'	4.00%		5.00%		5.50%
Expected average long-term increase in compensation level (in hundredths)	'	3.75%		4.00%		4.00%
Expected average long-term rate of return on assets (in hundredths)	'	7.25%		7.50%		8.00%
Allocated costs for pension plans sponsored by Xcel Energy Inc.	'	2,200,000		1,800,000		1,300,000
Expected average long-term rate of return on assets for next fiscal year (in hundredths)	'	7.25%		'		'
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 (in hundredths)	'	20.00%		'		'
Xcel Energy Inc.	'	'		'		'
Cash Flows [Abstract]	'	'		'		'
Total contributions to Xcel Energy's pension plans during the period	$130,000,000	$192,400,000		$198,100,000		$137,300,000
Number of pension plans to which contributions were made	3	4		4		3
[1]	Amounts are recognized in noncurrent liabilities on NSP-Wisconsin’s consolidated balance sheets.

Benefit_Plans_and_Other_Postre8

Benefit Plans and Other Postretirement Benefits, Defined Contribution Plans (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Defined Contribution Plans [Abstract]	'	'	'
Contributions to 401(k) and other defined contribution plans	$1.30	$1.20	$1.10

Benefit_Plans_and_Other_Postre9

Benefit Plans and Other Postretirement Benefits, Postretirement Health Care Benefits (Details) (Postretirement Benefit Plan)	12 Months Ended
	Dec. 31, 2013
Postretirement Benefit Plan	'
Postretirement Health Care Benefits [Abstract]	'
Amortization period for unrecognized accumulated postretirement benefit obligation (in years)	'20 years

Recovered_Sheet1

Benefit Plans and Other Postretirement Benefits, Fair Value of Postretirement Benefit Plan Assets (Details) (Postretirement Benefit Plan, USD $)	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
In Thousands, unless otherwise specified
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]	'	'	'	'
Fair value of plan assets	$746	$647	$746	'
Level 1	'	'	'	'
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]	'	'	'	'
Fair value of plan assets	31	123	'	'
Level 2	'	'	'	'
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]	'	'	'	'
Fair value of plan assets	715	469	'	'
Level 3	'	'	'	'
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]	'	'	'	'
Fair value of plan assets	0	55	62	51
Cash equivalents	'	'	'	'
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]	'	'	'	'
Fair value of plan assets	31	123	'	'
Cash equivalents | Level 1	'	'	'	'
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]	'	'	'	'
Fair value of plan assets	31	123	'	'
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	-2	'	'	'
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	-2	'	'	'
Derivatives | Level 3	'	'	'	'
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]	'	'	'	'
Fair value of plan assets	0	'	'	'
Government securities	'	'	'	'
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]	'	'	'	'
Fair value of plan assets	89	99	'	'
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	89	99	'	'
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	'	'
Insurance contracts	'	'	'	'
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]	'	'	'	'
Fair value of plan assets	80	67	'	'
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	80	67	'	'
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	'	'
Corporate bonds	'	'	'	'
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]	'	'	'	'
Fair value of plan assets	79	59	'	'
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	'	'
Corporate bonds | Level 2	'	'	'	'
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]	'	'	'	'
Fair value of plan assets	79	59	'	'
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	5	1	'	'
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	5	0	'	'
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	1	14	6
Mortgage-backed securities	'	'	'	'
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]	'	'	'	'
Fair value of plan assets	37	54	'	'
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	37	0	'	'
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	54	48	45
Commingled funds	'	'	'	'
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]	'	'	'	'
Fair value of plan assets	452	307	'	'
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	'	'
Commingled funds | Level 2	'	'	'	'
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]	'	'	'	'
Fair value of plan assets	452	307	'	'
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	'	'
Other	'	'	'	'
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]	'	'	'	'
Fair value of plan assets	-25	-63	'	'
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	-25	-63	'	'
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	'	'

Recovered_Sheet2

Benefit Plans and Other Postretirement Benefits, Changes in Level 3 Postretirement Benefit Plan Assets (Details) (Postretirement Benefit Plan, USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012	Dec. 31, 2011
Changes in Level 3 Plan Assets [Roll Forward]	'		'	'
Fair value of plan assets at Dec. 31	$746		$647	$746
Level 3	'		'	'
Changes in Level 3 Plan Assets [Roll Forward]	'		'	'
Fair value of plan assets at Jan. 1	55		62	51
Net realized gains (losses)	0		-1	-3
Net unrealized gains (losses)	0		9	4
Purchases, issuances and settlements, net	0		-15	10
Transfers in (out) of Level 3	-55	[1]	0	0
Fair value of plan assets at Dec. 31	0		55	62
Asset-backed securities	'		'	'
Changes in Level 3 Plan Assets [Roll Forward]	'		'	'
Fair value of plan assets at Dec. 31	5		1	'
Asset-backed securities | Level 3	'		'	'
Changes in Level 3 Plan Assets [Roll Forward]	'		'	'
Fair value of plan assets at Jan. 1	1		14	6
Net realized gains (losses)	0		0	0
Net unrealized gains (losses)	0		3	-2
Purchases, issuances and settlements, net	0		-16	10
Transfers in (out) of Level 3	-1	[1]	0	0
Fair value of plan assets at Dec. 31	0		1	14
Mortgage-backed securities	'		'	'
Changes in Level 3 Plan Assets [Roll Forward]	'		'	'
Fair value of plan assets at Dec. 31	37		54	'
Mortgage-backed securities | Level 3	'		'	'
Changes in Level 3 Plan Assets [Roll Forward]	'		'	'
Fair value of plan assets at Jan. 1	54		48	45
Net realized gains (losses)	0		-1	-3
Net unrealized gains (losses)	0		6	6
Purchases, issuances and settlements, net	0		1	0
Transfers in (out) of Level 3	-54	[1]	0	0
Fair value of plan assets at Dec. 31	$0		$54	$48
[1]	Transfers out of Level 3 into Level 2 were principally due to diminished use of unobservable inputs that were previously significant to these fair value measurements and were subsequently sold during 2013.

Recovered_Sheet3

Benefit Plans and Other Postretirement Benefits, Postretirement Benefit Plan Benefit Obligations, Cash Flows and Benefit Costs (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Funded Status of Plans at Dec. 31 [Abstract]	'	'	'
Noncurrent liabilities	($45,708,000)	($63,643,000)	'
Postretirement Benefit Plan	'	'	'
Change in Projected Benefit Obligation [Roll Forward]	'	'	'
Obligation at Jan. 1	19,432,000	22,127,000	'
Service cost	25,000	20,000	17,000
Interest cost	760,000	1,075,000	1,144,000
Medicare subsidy reimbursements	31,000	189,000	'
Plan amendments	0	-3,440,000	'
Plan participants' contributions	621,000	893,000	'
Actuarial (gain) loss	-1,724,000	1,486,000	'
Benefit payments	-1,992,000	-2,918,000	'
Obligation at Dec. 31	17,153,000	19,432,000	22,127,000
Change in Fair Value of Plan Assets [Roll Forward]	'	'	'
Fair value of plan assets at Jan. 1	647,000	746,000	'
Actual return (loss) on plan assets	-13,000	3,000	'
Plan participants' contributions	621,000	893,000	'
Employer contributions	1,483,000	1,923,000	'
Benefit payments	-1,992,000	-2,918,000	'
Fair value of plan assets at Dec. 31	746,000	647,000	746,000
Funded Status of Plans at Dec. 31 [Abstract]	'	'	'
Funded status	-16,407,000	-18,785,000	'
Current liabilities	-718,000	-943,000	'
Noncurrent liabilities	-15,689,000	-17,842,000	'
Net postretirement amounts recognized on consolidated balance sheets	-16,407,000	-18,785,000	'
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost [Abstract]	'	'	'
Net loss	11,098,000	13,730,000	'
Prior service (credit) cost	-3,187,000	-3,538,000	'
Transition obligation	0	1,000	'
Total	7,911,000	10,193,000	'
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	570,000	433,000	'
Noncurrent regulatory assets	7,341,000	9,760,000	'
Total	7,911,000	10,193,000	'
Significant Assumptions Used to Measure Benefit Obligations [Abstract]	'	'	'
Measurement date	'12/31/2013	'12/31/2012	'
Discount rate for year-end valuation (in hundredths)	4.82%	4.10%	'
Mortality table	'RP 2000	'RP 2000	'
Health care costs trend rate - initial (in hundredths)	7.00%	7.50%	'
Ultimate health care trend assumption rate (in hundredths)	4.50%	4.50%	'
Period until ultimate trend rate is reached (in years)	'5 years	'	'
Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rate [Abstract]	'	'	'
One-percent increase in APBO	1,773,000	'	'
One-percent decrease in APBO	-1,486,000	'	'
One-percent increase in service and interest components	78,000	'	'
One-percent decrease in service and interest components	-61,000	'	'
Cash Flows [Abstract]	'	'	'
Total contributions to Xcel Energy's postretirement health care plans during the year	1,500,000	1,900,000	2,400,000
Expected contribution to postretirement health care plans during 2014	1,500,000	'	'
Components of Net Periodic Benefit Cost (Credit) [Abstract]	'	'	'
Service cost	25,000	20,000	17,000
Interest cost	760,000	1,075,000	1,144,000
Expected return on plan assets	-42,000	-50,000	-74,000
Amortization of transition obligation	1,000	171,000	171,000
Amortization of prior service cost (credit)	-351,000	-14,000	-14,000
Amortization of net loss	963,000	486,000	366,000
Net periodic benefit cost	1,356,000	1,688,000	1,610,000
Significant Assumptions Used to Measure Costs [Abstract]	'	'	'
Discount rate (in hundredths)	4.10%	5.00%	5.50%
Expected average long-term rate of return on assets (in hundredths)	7.11%	6.75%	7.50%
Xcel Energy Inc. | Postretirement Benefit Plan	'	'	'
Cash Flows [Abstract]	'	'	'
Total contributions to Xcel Energy's postretirement health care plans during the year	17,600,000	47,100,000	49,000,000
Expected contribution to postretirement health care plans during 2014	$13,300,000	'	'

Recovered_Sheet4

Benefit Plans and Other Postretirement Benefits, Projected Benefit Payments (Details) (USD $)	Dec. 31, 2013
In Thousands, unless otherwise specified
Pension Plans	'
Defined Benefit Plan, Gross Projected Benefit Payments [Abstract]	'
2014	$21,677
2015	14,257
2016	13,420
2017	13,851
2018	12,983
2019-2023	64,935
Postretirement Benefit Plan	'
Defined Benefit Plan, Gross Projected Benefit Payments [Abstract]	'
2014	1,491
2015	1,459
2016	1,444
2017	1,384
2018	1,357
2019-2023	6,229
Expected Medicare Part D Subsidies [Abstract]	'
2014	27
2015	25
2016	24
2017	20
2018	18
2019-2023	82
Defined Benefit Plan, Net Projected Benefit Payments [Abstract]	'
2014	1,464
2015	1,434
2016	1,420
2017	1,364
2018	1,339
2019-2023	$6,147

Recovered_Sheet5

Benefit Plans and Other Postretirement Benefits, Multiemployer Plans (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
	Employer
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	1	'	'
Multiemployer contributions	$130	$163	$169
Multiemployer Pension Plans	'	'	'
Multiemployer Plans [Abstract]	'	'	'
Multiemployer contributions	$130	$163	$169

Other_Income_Net_Details

Other Income, Net (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Other Income and Expenses [Abstract]	'	'	'
Interest income	$538	$736	$324
Other nonoperating income	152	129	67
Insurance policy expense	-427	-389	-283
Other nonoperating expense	-10	0	-10
Other income, net	$253	$476	$98

Fair_Value_of_Financial_Assets2

Fair Value of Financial Assets and Liabilities, Derivative Instruments (Details) (USD $)	Dec. 31, 2013		Dec. 31, 2012
In Millions, unless otherwise specified	MMBTU		MMBTU
Interest Rate Contract [Member]	'		'
Interest Rate Derivatives [Abstract]	'		'
Amount of accumulated other comprehensive gains (losses) related to interest rate derivatives expected to be reclassified into earnings within the next twelve months	-0.1		'
Natural Gas Commodity Contract [Member]	'		'
Gross Notional Amounts of Commodity Options [Abstract]	'		'
Notional amount	987,000	[1],[2]	53,000	[1],[2]
[1]	Amounts are not reflective of net positions in the underlying commodities.
[2]	Notional amounts for options are included on a gross basis, but are weighted for the probability of exercise.

Fair_Value_of_Financial_Assets3

Fair Value of Financial Assets and Liabilities, Financial Impact of Qualifying Cash Flow Hedges (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
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	($437)	($514)	($590)
After-tax net realized losses on derivative transactions reclassified into earnings	76	77	76
Accumulated other comprehensive loss related to cash flow hedges at Dec. 31	($361)	($437)	($514)

Fair_Value_of_Financial_Assets4

Fair Value of Financial Assets and Liabilities, Impact of Derivative Activity (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Financial Impact of Qualifying Fair Value Hedges on Earnings [Abstract]	'	'	'
Derivative instruments designated as fair value hedges	$0	$0	$0
Gain (Loss) on Fair Value Hedges Recognized in Earnings	0	0	0
Cash Flow Hedging [Member] | Interest Rate Contract [Member]	'	'	'
Impact of Derivative Activity on Accumulated Other Comprehensive Income (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
Not Designated as Hedging Instrument [Member] | Natural Gas Commodity Contract [Member]	'	'	'
Impact of Derivative Activity on Accumulated Other Comprehensive Income (Loss) Regulatory Assets and Liabilities and Income [Abstract]	'	'	'
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities	-100,000	-400,000	-3,600,000
Derivative Instruments Gain Loss Reclassified To Regulatory Assets And Liabilities Net	($700,000)	($2,900,000)	($2,900,000)

Fair_Value_of_Financial_Assets5

Fair Value of Financial Assets and Liabilities, Derivative Assets and Liabilities at Fair Value (Details) (USD $)	Dec. 31, 2013		Dec. 31, 2012
In Thousands, unless otherwise specified
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'		'
Prepayments and other	$5,056		$4,394
Other current liabilities	9,376		10,955
Fair Value Measured on a Recurring Basis [Member] | Other Current Assets [Member] | Natural Gas Commodity [Member]	'		'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'		'
Derivative Asset, Fair Value, Gross Asset	580	[1]	'
Fair Value Measured on a Recurring Basis [Member] | Other Current Liabilities [Member] | Natural Gas Commodity [Member]	'		'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'		'
Derivative Liability, Fair Value, Gross Liability	'		11	[2]
Fair Value Measured on a Recurring Basis [Member] | Level 1 | Other Current Assets [Member] | Natural Gas Commodity [Member]	'		'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'		'
Derivative Asset, Fair Value, Gross Asset	0		'
Fair Value Measured on a Recurring Basis [Member] | Level 1 | Other Current Liabilities [Member] | Natural Gas Commodity [Member]	'		'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'		'
Derivative Liability, Fair Value, Gross Liability	'		0
Fair Value Measured on a Recurring Basis [Member] | Level 2 | Other Current Assets [Member] | Natural Gas Commodity [Member]	'		'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'		'
Derivative Asset, Fair Value, Gross Asset	580		'
Fair Value Measured on a Recurring Basis [Member] | Level 2 | Other Current Liabilities [Member] | Natural Gas Commodity [Member]	'		'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'		'
Derivative Liability, Fair Value, Gross Liability	'		11
Fair Value Measured on a Recurring Basis [Member] | Level 3 | Other Current Assets [Member] | Natural Gas Commodity [Member]	'		'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'		'
Derivative Asset, Fair Value, Gross Asset	0		'
Fair Value Measured on a Recurring Basis [Member] | Level 3 | Other Current Liabilities [Member] | Natural Gas Commodity [Member]	'		'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'		'
Derivative Liability, Fair Value, Gross Liability	'		0
Fair Value Measured on a Recurring Basis [Member] | Fair Value Total [Member]	'		'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'		'
Prepayments and other	5,100		'
Other current liabilities	'		11,000
Fair Value Measured on a Recurring Basis [Member] | Fair Value Total [Member] | Other Current Assets [Member] | Natural Gas Commodity [Member]	'		'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'		'
Derivative Asset, Fair Value, Gross Asset	580		'
Fair Value Measured on a Recurring Basis [Member] | Fair Value Total [Member] | Other Current Liabilities [Member] | Natural Gas Commodity [Member]	'		'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'		'
Derivative Liability, Fair Value, Gross Liability	'		11
Fair Value Measured on a Recurring Basis [Member] | Counterparty Netting [Member] | Other Current Assets [Member] | Natural Gas Commodity [Member]	'		'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'		'
Derivative Asset, Fair Value, Gross Asset	0	[3]	'
Fair Value Measured on a Recurring Basis [Member] | Counterparty Netting [Member] | Other Current Liabilities [Member] | Natural Gas Commodity [Member]	'		'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'		'
Derivative Liability, Fair Value, Gross Liability	'		$0	[3]
[1]	Included in other current assets balance of $5.1 million at Dec. 31, 2013 in the consolidated balance sheets.
[2]	Included in other current liabilities balance of $11.0 million at Dec. 31, 2012 in the consolidated balance sheets.
[3]	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, 2013 and 2012. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.

Fair_Value_of_Financial_Assets6

Fair Value of Financial Assets and Liabilities, Fair Value of Long-Term Debt (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Carrying Amount	'	'
Financial Liabilities, Balance Sheet Groupings [Abstract]	'	'
Long-term debt, including current portion	$468,597	$468,563
Fair Value	'	'
Financial Liabilities, Balance Sheet Groupings [Abstract]	'	'
Long-term debt, including current portion	$518,269	$576,353

Rate_Matters_Details

Rate Matters (Details) (Public Service Commission of Wisconsin (PSCW), USD $)	1 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Oct. 31, 2013	31-May-13
Electric and Gas Rate Case 2014, Electric Rates	'	'	'
Public Utilities, General Disclosures [Line Items]	'	'	'
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount	'	$34.30	'
Public Utilities, Requested Rate Increase (Decrease), Amount	'	'	40
Public Utilities, Requested Rate Increase (Decrease), Percentage	'	'	6.50%
Public utilities, Adjustment to requested rate increase (decrease) related to DOE settlement proceeds, amount	'	'	-4.5
Public Utilities, Approved Rate Increase (Decrease), Amount	19.5	'	'
Public Utilities, Approved Rate Increase (Decrease), Percentage	3.10%	'	'
Public Utilities, Approved Return on Equity, Percentage	10.20%	'	'
Public Utilities, Approved Equity Capital Structure, Percentage	52.50%	'	'
Public Utilities, Authorized Deferrals	4.1	'	'
Electric and Gas Rate Case 2014, Gas Rates	'	'	'
Public Utilities, General Disclosures [Line Items]	'	'	'
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount	'	0	'
Public Utilities, Requested Rate Increase (Decrease), Amount	'	'	4.7
Public Utilities, Requested Rate Increase (Decrease), Percentage	'	'	3.80%
Electric and Gas Rate Case 2014	'	'	'
Public Utilities, General Disclosures [Line Items]	'	'	'
Public Utilities, Requested Return on Equity, Percentage	'	10.40%	10.40%
Public Utilities, Requested Equity Capital Structure, Percentage	'	'	52.50%
Forecasted Average Net Investment Rate Base, Electric Utility	'	'	895.3
Forecasted Average Net Investment Rate Base, Natural Gas Utility	'	'	$89.80

Commitments_and_Contingencies_1

Commitments and Contingencies, Capital Commitments (Details)	12 Months Ended
	Dec. 31, 2013
	Project
Capital Commitments [Abstract]	'
Number of major projects with capital commitments	1
Minimum annual tolerance band percentage for future rate recovery or refund of fuel costs	2.00%
Capital Commitments [Member] | CapX2020 [Member]	'
Capital Commitments [Abstract]	'
Number of transmission lines in Group 1 project	4

Commitments_and_Contingencies_2

Commitments and Contingencies, Fuel Contracts (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013
Fuel Contracts [Abstract]	'
Minimum annual tolerance band percentage for future rate recovery or refund of fuel costs (in hundredths)	2.00%
Coal [Member]	'
Fuel Contracts [Abstract]	'
2014	6.2
2015	1.3
2016	0.7
2017	0.7
2018	0.7
Thereafter	4.1
Total	13.7	[1]
Natural Gas Supply [Member]	'
Fuel Contracts [Abstract]	'
2014	13.4
2015	0.3
2016	0.3
2017	0.2
2018	0
Thereafter	0
Total	14.2	[1]
Natural Gas Storage and Transportation [Member]	'
Fuel Contracts [Abstract]	'
2014	11.9
2015	11.6
2016	11.7
2017	9.5
2018	4.4
Thereafter	18.9
Total	68	[1]
[1]	Excludes additional amounts allocated to NSP-Wisconsin through intercompany charges.

Commitments_and_Contingencies_3

Commitments and Contingencies, Leases (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Operating Leases [Abstract]	'	'	'
Total expenses under operating lease obligations	$1.40	$1.10	$1.40
Other [Member]	'	'	'
Operating Leases, Future Minimum Payments Due [Abstract]	'	'	'
2014	0.8	'	'
2015	0.8	'	'
2016	0.8	'	'
2017	0.9	'	'
2018	0.9	'	'
Thereafter	8.8	'	'
Total	$13	'	'

Commitments_and_Contingencies_4

Commitments and Contingencies, Variable Interest Entities (Details) (Low-Income Housing Limited Partnerships [Member], USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Low-Income Housing Limited Partnerships [Member]	'	'
Amounts Reflected in Consolidated Balance Sheets [Abstract]	'	'
Current assets	$223	$357
Property, plant and equipment, net	2,427	2,599
Other noncurrent assets	112	105
Total assets	2,762	3,061
Current liabilities	233	1,388
Mortgages and other long-term debt payable	1,687	617
Other noncurrent liabilities	42	39
Total liabilities	$1,962	$2,044

Commitments_and_Contingencies_5

Commitments and Contingencies, Joint Operating System (Details) (USD $)	12 Months Ended
	Dec. 31, 2013
	Counterparty
Joint Operating System [Abstract]	'
Number of companies covered by FERC approved Interchange Agreement	2
NSP-Minnesota | Nuclear Insurance [Member]	'
Joint Operating System [Abstract]	'
Maximum possible loss contingency	13,600,000,000
Nuclear insurance coverage secured for the company's public liability exposure	375,000,000
Nuclear insurance coverage exposure funded by the Secondary Financial Protection Program	13,200,000,000
Maximum assessments per reactor per accident	127,300,000
Number of owned and licensed reactors	3
Maximum funding requirement per reactor for any one year	19,000,000
Term for maximum installment payment assessment per reactor (in years)	'1 year
Insurance coverage limits for NSP-Minnesota's nuclear plant sites	2,300,000,000
Number of nuclear plant sites operated by NSP-Minnesota	2
Maximum assessments for business interruption insurance each calendar year	16,100,000
Maximum assessment for property damage insurance NSP-Minnesota is subject to each calendar year	40,200,000

Commitments_and_Contingencies_6

Commitments and Contingencies, Guarantees (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013
Guarantee [Abstract]	'
Assets held as collateral	$0
Payment or Performance Guarantee [Member] | Customer Loans for Farm Rewiring Program [Member]	'
Guarantee [Abstract]	'
Guarantee amount	1	[1]
Current exposure	$0.30	[1]
Term or expiration date	'2017	[1]
[1]	The debtor becomes the subject of bankruptcy or other insolvency proceedings.

Commitments_and_Contingencies_7

Commitments and Contingencies, Environmental Contingencies - Site Contingencies (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
	Site
Manufactured Gas Plant (MGP) Site [Abstract]	'	'
Liability for estimated cost of remediating sites, current	$28,785,000	$23,427,000
Ashland MGP Site	'	'
Manufactured Gas Plant (MGP) Site [Abstract]	'	'
Number of properties included in superfund site which NSP-Wisconsin does not own	2	'
Liability for estimated cost of remediating sites	104,600,000	103,700,000
Liability for estimated cost of remediating sites, current	25,200,000	20,100,000
Amortization period for recovery of remediation costs in natural gas rates, low end of range (in years)	'4 years	'
Amortization period for recovery of remediation costs in natural gas rates, high end of range (in years)	'6 years	'
Ashland MGP Site - Phase I Project Area	'	'
Manufactured Gas Plant (MGP) Site [Abstract]	'	'
Liability for estimated cost of remediating sites	40,000,000	'
Number of acres of land conveyed to the State of Wisconsin and tribal trustees (in acres)	1,390	'
Approved amortization period for recovery of remediation costs in natural gas rates (in years)	'10 years	'
Carrying cost percentage to be applied to the unamortized regulatory asset for MGP remediation (in hundredths)	3.00%	'
Approved increase (decrease) in amortization expense granted by a regulatory body	1,100,000	'
Ashland MGP Site - Sediments	'	'
Manufactured Gas Plant (MGP) Site [Abstract]	'	'
Estimated cost of remediating site, low end of range	63,000,000	'
Estimated cost of remediating site, high end of range	77,000,000	'
Potential percent of increase to the high end of the range of estimated site remediation costs (in hundredths)	50.00%	'
Potential percent of decrease to the low end of the range of estimated site remediation costs (in hundredths)	30.00%	'
Other MGP Sites	'	'
Manufactured Gas Plant (MGP) Site [Abstract]	'	'
Liability for estimated cost of remediating sites	$3,900,000	$2,500,000
Number of identified MGP sites under current investigation and/or remediation	2	'

Commitments_and_Contingencies_8

Commitments and Contingencies Commitments and Contingencies, Environmental Contingencies - Unrecorded Unconditional Purchase Obligation (Details) (USD $)	Jun. 30, 2013	Dec. 31, 2013	Apr. 30, 2012	Dec. 31, 2013
In Millions, unless otherwise specified	Federal Clean Water Act	EPA GHG Regulation	Electric Generating Unit Mercury And Air Toxics Standards Rule	Capital Commitments
	Regulation		MW	Industrial Boiler Maximum Achievable Control Technology Rules
Environmental Requirements [Abstract]	'	'	'	'
Number of potential regulatory options under the proposed Effluent Limitations Guidelines rule	4	'	'	'
Number of issues granted review by the U.S. Supreme Court	'	1	'	'
Generating capacity (in MW)	'	'	25	'
Number of years before affected facilities must demonstrate compliance, low end of range	'	'	'3 years	'
Number of years before affected facilities must demonstrate compliance, high end of range	'	'	'4 years	'
Liability for estimated cost to comply with regulation	'	'	'	$17.20

Commitments_and_Contingencies_9

Commitments and Contingencies, Asset Retirement Obligations (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]	'		'
Beginning balance	$3,036	[1],[2]	$424	[1]
Liabilities recognized	0		1,962
Liabilities settled	0		0
Accretion	84		17
Revisions to prior estimates	-267		633
Ending balance	2,853	[1],[2]	3,036	[1],[2]
Electric Plant Steam Production Asbestos	'		'
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]	'		'
Beginning balance	1,962	[2]	0
Liabilities recognized	0		1,962
Accretion	43		0
Revisions to prior estimates	0		0
Ending balance	2,005	[2]	1,962	[2]
Electric Plant Steam and Other Production Ash Containment	'		'
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]	'		'
Beginning balance	125	[2]	120
Liabilities recognized	0		0
Accretion	12		5
Revisions to prior estimates	224		0
Ending balance	361	[2]	125	[2]
Electric Plant Electric Distribution	'		'
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]	'		'
Beginning balance	13	[2]	13
Liabilities recognized	0		0
Accretion	1		0
Revisions to prior estimates	22		0
Ending balance	36	[2]	13	[2]
Electric Plant Other	'		'
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]	'		'
Beginning balance	826	[2]	186
Liabilities recognized	0		0
Accretion	20		7
Revisions to prior estimates	-557		633
Ending balance	289	[2]	826	[2]
Natural Gas Plant Gas Transmission and Distribution	'		'
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]	'		'
Beginning balance	75	[2]	71
Liabilities recognized	0		0
Accretion	5		4
Revisions to prior estimates	-5		0
Ending balance	75	[2]	75	[2]
Common and Other Property Common Miscellaneous	'		'
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]	'		'
Beginning balance	35	[2]	34
Liabilities recognized	0		0
Accretion	3		1
Revisions to prior estimates	49		0
Ending balance	$87	[2]	$35	[2]
[1]	Included in the other long-term liabilities balance in the consolidated balance sheets.
[2]	There were no ARO liabilities settled during the 12 months ended Dec. 31, 2013 or 2012.

Recovered_Sheet6

Commitments and Contingencies Commitments and Contingencies, Removal Costs (Details) (Plant Removal Costs, USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Plant Removal Costs	'	'
Regulatory Liabilities [Line Items]	'	'
Regulatory Liabilities	$116	$114

Regulatory_Assets_and_Liabilit2

Regulatory Assets and Liabilities, Regulatory Assets (Details) (USD $)	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012
Regulatory Assets [Line Items]	'		'
Regulatory Asset, Current	$14,866,000		$12,048,000
Regulatory Asset, Noncurrent	233,193,000		240,459,000
Past expenditures not currently earning a return	100,000		400,000
Environmental Remediation Costs	'		'
Regulatory Assets [Line Items]	'		'
Regulatory Asset, Current	4,376,000		2,521,000
Regulatory Asset, Noncurrent	117,684,000		109,162,000
Regulatory asset, remaining amortization period	'Various		'
Pension and Retiree Medical Obligations	'		'
Regulatory Assets [Line Items]	'		'
Regulatory Asset, Current	8,202,000	[1]	7,328,000	[1]
Regulatory Asset, Noncurrent	85,220,000	[1]	104,426,000	[1]
Regulatory asset, remaining amortization period	'Various		'
Recoverable Deferred Taxes on AFUDC Recorded in Plant	'		'
Regulatory Assets [Line Items]	'		'
Regulatory Asset, Current	0		0
Regulatory Asset, Noncurrent	12,679,000		10,458,000
Regulatory asset, remaining amortization period	'Plant lives		'
Losses on Reacquired Debt	'		'
Regulatory Assets [Line Items]	'		'
Regulatory Asset, Current	801,000		800,000
Regulatory Asset, Noncurrent	5,737,000		6,538,000
Regulatory asset, remaining amortization period	'Term of related debt		'
State Commission Adjustments	'		'
Regulatory Assets [Line Items]	'		'
Regulatory Asset, Current	410,000		339,000
Regulatory Asset, Noncurrent	9,355,000		7,533,000
Regulatory asset, remaining amortization period	'Plant lives		'
Conservation Programs	'		'
Regulatory Assets [Line Items]	'		'
Regulatory Asset, Current	404,000		691,000
Regulatory Asset, Noncurrent	0		0
Regulatory asset, remaining amortization period	'Less than one year		'
Deferred Income Tax Adjustment	'		'
Regulatory Assets [Line Items]	'		'
Regulatory Asset, Current	0		0
Regulatory Asset, Noncurrent	1,763,000		1,974,000
Regulatory asset, remaining amortization period	'Typically plant lives		'
Recoverable Purchased Natural Gas And Electric Energy Costs	'		'
Regulatory Assets [Line Items]	'		'
Regulatory Asset, Current	673,000		358,000
Regulatory Asset, Noncurrent	0		0
Regulatory asset, remaining amortization period	'Less than one year		'
Other Regulatory Assets	'		'
Regulatory Assets [Line Items]	'		'
Regulatory Asset, Current	0		11,000
Regulatory Asset, Noncurrent	$755,000		$368,000
Regulatory asset, remaining amortization period	'Various		'
[1]	Includes the non-qualified pension plan.

Regulatory_Assets_and_Liabilit3

Regulatory Assets and Liabilities, Regulatory Liabilities (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Regulatory Liabilities [Line Items]	'	'
Regulatory Liability, Current	$9,717	$6,086
Regulatory Liability, Noncurrent	126,424	123,746
Plant Removal Costs	'	'
Regulatory Liabilities [Line Items]	'	'
Regulatory Liability, Current	0	0
Regulatory Liability, Noncurrent	116,293	113,949
Regulatory liability, remaining amortization period	'Plant lives	'
DOE Settlement	'	'
Regulatory Liabilities [Line Items]	'	'
Regulatory Liability, Current	6,814	5,628
Regulatory Liability, Noncurrent	0	0
Regulatory liability, remaining amortization period	'Less than one year	'
Investment Tax Credit Deferrals	'	'
Regulatory Liabilities [Line Items]	'	'
Regulatory Liability, Current	0	0
Regulatory Liability, Noncurrent	9,976	9,626
Regulatory liability, remaining amortization period	'Various	'
Conservation Programs	'	'
Regulatory Liabilities [Line Items]	'	'
Regulatory Liability, Current	1,187	73
Regulatory Liability, Noncurrent	0	0
Regulatory liability, remaining amortization period	'Less than one year	'
Deferred Electric Production And Natural Gas Costs	'	'
Regulatory Liabilities [Line Items]	'	'
Regulatory Liability, Current	1,542	134
Regulatory Liability, Noncurrent	0	0
Regulatory liability, remaining amortization period	'Less than one year	'
Other Regulatory Liabilities	'	'
Regulatory Liabilities [Line Items]	'	'
Regulatory Liability, Current	174	251
Regulatory Liability, Noncurrent	$155	$171
Regulatory liability, remaining amortization period	'Various	'

Other_Comprehensive_Income_Det

Other Comprehensive Income (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012	Dec. 31, 2011
Accumulated Other Comprehensive Income [Roll Forward]	'		'	'
Accumulated other comprehensive loss at beginning of period	($437)		'	'
Accumulated other comprehensive loss at end of period	-361		-437	'
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]	'		'	'
Total, pre-tax	-95,877		-79,509	-84,620
Income Tax Expense (Benefit)	36,409		29,558	33,614
Gains and Losses on Cash Flow Hedges [Member]	'		'	'
Accumulated Other Comprehensive Income [Roll Forward]	'		'	'
Accumulated other comprehensive loss at beginning of period	-437		'	'
Losses reclassified from net accumulated other comprehensive loss	76		'	'
Net current period other comprehensive income (loss)	76		'	'
Accumulated other comprehensive loss at end of period	-361		'	'
Gains and Losses on Cash Flow Hedges [Member] | Amounts Reclassified from Accumulated Other Comprehensive Loss [Member]	'		'	'
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]	'		'	'
Total, pre-tax	127		'	'
Income Tax Expense (Benefit)	-51		'	'
Total, net of tax	76		'	'
Gains and Losses on Cash Flow Hedges [Member] | Interest Rate Derivatives [Member] | Amounts Reclassified from Accumulated Other Comprehensive Loss [Member]	'		'	'
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]	'		'	'
Interest charges	$127	[1]	'	'
[1]	Included in interest charges.

Segments_and_Related_Informati2

Segments and Related Information (Details) (USD $)

3 Months Ended

12 Months Ended

In Thousands, unless otherwise specified

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2012

Sep. 30, 2012

Jun. 30, 2012

Mar. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Segment Reporting Information [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Intercompany revenue

'

'

'

'

'

'

'

'

$136,917

$125,344

$124,334

Operating revenues

240,388

231,060

210,175

241,415

217,395

226,475

194,173

223,799

923,038

861,842

875,790

Depreciation and amortization

'

'

'

'

'

'

'

'

76,897

69,234

68,574

Total interest charges and financing costs

'

'

'

'

'

'

'

'

25,816

22,937

23,993

Income Tax Expense (Benefit)

'

'

'

'

'

'

'

'

36,409

29,558

33,614

Net income

7,225

22,013

10,544

19,685

7,131

22,200

5,742

14,878

59,468

49,951

51,006

Regulated Electric

'

'

'

'

'

'

'

'

'

'

'

Segment Reporting Information [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Operating revenues

'

'

'

'

'

'

'

'

789,518

757,920

755,541

Depreciation and amortization

'

'

'

'

'

'

'

'

64,237

59,768

58,800

Total interest charges and financing costs

'

'

'

'

'

'

'

'

22,966

20,303

21,181

Income Tax Expense (Benefit)

'

'

'

'

'

'

'

'

33,691

27,164

32,656

Net income

'

'

'

'

'

'

'

'

51,334

45,377

47,093

Regulated Natural Gas

'

'

'

'

'

'

'

'

'

'

'

Segment Reporting Information [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Operating revenues

'

'

'

'

'

'

'

'

134,834

103,827

121,028

Depreciation and amortization

'

'

'

'

'

'

'

'

12,485

9,251

9,599

Total interest charges and financing costs

'

'

'

'

'

'

'

'

2,749

2,554

2,675

Income Tax Expense (Benefit)

'

'

'

'

'

'

'

'

4,623

2,113

1,995

Net income

'

'

'

'

'

'

'

'

6,501

3,094

2,964

All Other

'

'

'

'

'

'

'

'

'

'

'

Segment Reporting Information [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Operating revenues

'

'

'

'

'

'

'

'

1,003

1,177

1,207

Depreciation and amortization

'

'

'

'

'

'

'

'

175

215

175

Total interest charges and financing costs

'

'

'

'

'

'

'

'

101

80

137

Income Tax Expense (Benefit)

'

'

'

'

'

'

'

'

-1,905

281

-1,037

Net income

'

'

'

'

'

'

'

'

1,633

1,480

949

Operating Segments

'

'

'

'

'

'

'

'

'

'

'

Segment Reporting Information [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Operating revenues

'

'

'

'

'

'

'

'

923,038

[1]

861,842

[1]

875,790

[1]

Operating Segments | Regulated Electric

'

'

'

'

'

'

'

'

'

'

'

Segment Reporting Information [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Operating revenues

'

'

'

'

'

'

'

'

789,168

[1]

757,565

[1]

755,136

[1]

Operating Segments | Regulated Natural Gas

'

'

'

'

'

'

'

'

'

'

'

Segment Reporting Information [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Operating revenues

'

'

'

'

'

'

'

'

132,867

[1]

103,100

[1]

119,447

[1]

Operating Segments | All Other

'

'

'

'

'

'

'

'

'

'

'

Segment Reporting Information [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Operating revenues

'

'

'

'

'

'

'

'

1,003

[1]

1,177

[1]

1,207

[1]

Intersegment Eliminations

'

'

'

'

'

'

'

'

'

'

'

Segment Reporting Information [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Operating revenues

'

'

'

'

'

'

'

'

-2,317

-1,082

-1,986

Depreciation and amortization

'

'

'

'

'

'

'

'

0

0

0

Total interest charges and financing costs

'

'

'

'

'

'

'

'

0

0

0

Income Tax Expense (Benefit)

'

'

'

'

'

'

'

'

0

0

0

Net income

'

'

'

'

'

'

'

'

0

0

0

Intersegment Eliminations | Regulated Electric

'

'

'

'

'

'

'

'

'

'

'

Segment Reporting Information [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Operating revenues

'

'

'

'

'

'

'

'

350

355

405

Intersegment Eliminations | Regulated Natural Gas

'

'

'

'

'

'

'

'

'

'

'

Segment Reporting Information [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Operating revenues

'

'

'

'

'

'

'

'

1,967

727

1,581

Intersegment Eliminations | All Other

'

'

'

'

'

'

'

'

'

'

'

Segment Reporting Information [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Operating revenues

'

'

'

'

'

'

'

'

$0

$0

$0

[1]

Operating revenues include $137 million, $125 million and $124 million of intercompany revenue for the years ended Dec. 31, 2013, 2012 and 2011, respectively. See Note 15 for further discussion of related party transactions by operating segment.

Schedule_II_Valuation_and_Qual1

Schedule II, Valuation and Qualifying Accounts (Details) (Allowance for Bad Debts, USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Allowance for Bad Debts	'		'		'
Movement in Valuation Allowances and Reserves [Roll Forward]	'		'		'
Balance at Jan. 1	$4,333		$4,766		$4,262
Charged to costs and expenses	3,988		3,329		3,842
Charged to other accounts	1,199	[1]	1,310	[1]	1,241	[1]
Deductions from reserves	4,609	[2]	5,072	[2]	4,579	[2]
Balance at Dec. 31	$4,911		$4,333		$4,766
[1]	Recovery of amounts previously written off.
[2]	Principally bad debts written off.

Related_Party_Transactions_Det

Related Party Transactions (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Operating revenues	'	'	'
Electric	$136,917	$125,344	$124,334
Operating expenses	'	'	'
Purchased power	416,173	405,016	399,649
Transmission expense	42,460	44,942	40,870
Natural gas purchased for resale	97	116	98
Other operating expenses - paid to Xcel Energy Services Inc.	61,531	54,137	54,885
Interest expense	22	22	48
Accounts Receivable and Payable with Affiliates [Abstract]	'	'	'
Accounts receivable	1,595	586	'
Accounts payable	24,986	31,556	'
NSP-Minnesota	'	'	'
Accounts Receivable and Payable with Affiliates [Abstract]	'	'	'
Accounts receivable	0	0	'
Accounts payable	18,584	26,632	'
PSCo	'	'	'
Accounts Receivable and Payable with Affiliates [Abstract]	'	'	'
Accounts receivable	0	0	'
Accounts payable	8	71	'
SPS	'	'	'
Accounts Receivable and Payable with Affiliates [Abstract]	'	'	'
Accounts receivable	26	0	'
Accounts payable	0	4	'
Other subsidiaries of Xcel Energy Inc.	'	'	'
Accounts Receivable and Payable with Affiliates [Abstract]	'	'	'
Accounts receivable	1,569	586	'
Accounts payable	$6,394	$4,849	'

Summarized_Quarterly_Financial2

Summarized Quarterly Financial Data (Unaudited) (Details) (USD $)	3 Months Ended								12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Quarterly Financial Information Disclosure [Abstract]	'	'	'	'	'	'	'	'	'	'	'
Operating revenues	$240,388	$231,060	$210,175	$241,415	$217,395	$226,475	$194,173	$223,799	$923,038	$861,842	$875,790
Operating income	16,545	40,769	22,466	37,401	15,869	40,735	14,348	28,914	117,181	99,866	107,508
Net income	$7,225	$22,013	$10,544	$19,685	$7,131	$22,200	$5,742	$14,878	$59,468	$49,951	$51,006