Southwestern Public Service 10-K 24 Feb 14 2013 FY 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	'SOUTHWESTERN PUBLIC SERVICE CO	'	'
Entity Central Index Key	'0000092521	'	'
Current Fiscal Year End Date	'--12-31	'	'
Entity Well-known Seasoned Issuer	'No	'	'
Entity Voluntary Filers	'No	'	'
Entity Current Reporting Status	'Yes	'	'
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	'FY	'	'
Amendment Flag	'false	'	'
Entity Public Float	'	'	$0
Entity Common Stock, Shares Outstanding	'	100	'

STATEMENTS_OF_CASH_FLOWS

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	$95,177	$106,369	$89,901
Adjustments to reconcile net income to cash provided by operating activities:	'	'	'
Depreciation and amortization	124,069	115,917	109,207
Demand side management program amortization	1,673	1,811	1,811
Deferred income taxes	36,475	54,119	55,508
Amortization of investment tax credits	-341	-327	-275
Allowance for equity funds used during construction	-10,186	-7,272	-5,342
Provision for bad debts	3,437	2,915	3,655
Gain on sale of transmission assets	-13,661	0	0
Net derivative losses	268	269	268
Changes in operating assets and liabilities:	'	'	'
Accounts receivable	-36,184	-3,429	-23,518
Accrued unbilled revenues	-10,315	5,250	6,042
Inventories	-7,443	4,238	-5,726
Prepayments and other	4,456	-3,901	-2,480
Accounts payable	20,650	-13,730	-1,527
Net regulatory assets and liabilities	620	24,243	6,090
Other current liabilities	51,880	1,780	5,717
Pension and other employee benefit obligations	-17,968	-13,706	-7,576
Change in other noncurrent assets	-2,281	-1,541	1,509
Change in other noncurrent liabilities	-2,689	-1,912	-4,299
Net cash provided by operating activities	237,637	271,093	228,965
Investing activities	'	'	'
Utility capital/construction expenditures	-584,736	-384,626	-308,223
Proceeds from sale of transmission assets	37,118	0	0
Allowance for equity funds used during construction	10,186	7,272	5,342
Investments in utility money pool arrangement	-12,000	-217,000	-40,300
Receipts from utility money pool arrangement	12,000	217,000	40,300
Other, net	0	0	221
Net cash used in investing activities	-537,432	-377,354	-302,660
Financing activities	'	'	'
Proceeds from (repayment of) short-term borrowings, net	75,000	9,000	-49,000
Proceeds from issuance of long-term debt	94,626	108,678	193,137
Repayment of long-term debt	0	0	-101,800
Borrowings under utility money pool arrangement	767,000	265,000	293,500
Repayments under utility money pool arrangement	-729,000	-270,000	-288,500
Capital contributions from parent	162,277	60,024	89,631
Dividends paid to parent	-69,579	-66,609	-64,401
Net cash provided by financing activities	300,324	106,093	72,567
Net change in cash and cash equivalents	529	-168	-1,128
Cash and cash equivalents at beginning of period	482	650	1,778
Cash and cash equivalents at end of period	1,011	482	650
Supplemental disclosure of cash flow information:	'	'	'
Cash paid for interest (net of amounts capitalized)	-67,209	-61,268	-57,122
Cash paid for income taxes, net	-16,721	-13,763	-2,245
Supplemental disclosure of non-cash investing transactions:	'	'	'
Property, plant and equipment additions in accounts payable	$23,305	$38,751	$23,570

STATEMENTS_OF_COMMON_STOCKHOLD

STATEMENTS OF COMMON STOCKHOLDER'S EQUITY (USD $)	Total	Common stock	Additional Paid In Capital	Retained Earnings	Accumulated Other Comprehensive Income (Loss)
In Thousands, except Share data, unless otherwise specified
Beginning Balance at Dec. 31, 2010	$962,113	$0	$693,531	$270,257	($1,675)
Beginning Balance (in shares) at Dec. 31, 2010	'	100	'	'	'
Comprehensive income:	'	'	'	'	'
Net income	89,901	'	'	89,901	'
Other comprehensive income	171	'	'	'	171
Common dividends declared to parent	-64,957	'	'	-64,957	'
Contribution of capital by parent	89,631	'	89,631	'	'
Ending Balance at Dec. 31, 2011	1,076,859	0	783,162	295,201	-1,504
Ending Balance (in shares) at Dec. 31, 2011	'	100	'	'	'
Comprehensive income:	'	'	'	'	'
Net income	106,369	'	'	106,369	'
Other comprehensive income	172	'	'	'	172
Common dividends declared to parent	-66,469	'	'	-66,469	'
Contribution of capital by parent	60,024	'	60,024	'	'
Ending Balance at Dec. 31, 2012	1,176,955	0	843,186	335,101	-1,332
Ending Balance (in shares) at Dec. 31, 2012	100	100	'	'	'
Comprehensive income:	'	'	'	'	'
Net income	95,177	'	'	'	'
Other comprehensive income	171	'	'	'	171
Common dividends declared to parent	-70,889	'	'	-70,889	'
Contribution of capital by parent	162,277	'	162,277	'	'
Ending Balance at Dec. 31, 2013	$1,363,691	$0	$1,005,463	$359,389	($1,161)
Ending Balance (in shares) at Dec. 31, 2013	100	100	'	'	'

STATEMENTS_OF_INCOME

STATEMENTS OF INCOME (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Income Statement [Abstract]	'	'	'
Operating revenues	$1,707,087	$1,540,055	$1,707,565
Operating expenses	'	'	'
Electric fuel and purchased power	1,059,330	889,567	1,089,415
Operating and maintenance expenses	253,880	251,853	251,886
Demand side management program expenses	12,420	12,891	15,415
Depreciation and amortization	121,907	113,743	106,974
Taxes (other than income taxes)	49,533	46,246	43,278
Total operating expenses	1,497,070	1,314,300	1,506,968
Operating income	210,017	225,755	200,597
Other income, net	140	46	406
Allowance for funds used during construction b equity	10,186	7,272	5,342
Interest charges and financing costs	'	'	'
Interest charges b includes other financing costs of $3,031, $2,996 and $2,964, respectively	77,866	69,074	65,095
Allowance for funds used during construction b debt	-6,461	-4,599	-3,784
Total interest charges and financing costs	71,405	64,475	61,311
Income before income taxes	148,938	168,598	145,034
Income taxes	53,761	62,229	55,133
Net income	$95,177	$106,369	$89,901

STATEMENTS_OF_INCOME_Parenthet

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	$3,031	$2,996	$2,964

BALANCE_SHEETS

BALANCE SHEETS (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Current assets	'	'
Cash and cash equivalents	$1,011	$482
Accounts receivable, net	70,951	62,067
Accounts receivable from affiliates	15,840	4,791
Accrued unbilled revenues	109,207	98,892
Inventories	37,138	31,337
Regulatory assets	27,595	24,020
Derivative instruments	17,826	7,892
Deferred income taxes	85,362	27,528
Prepayments and other	19,571	11,387
Total current assets	384,501	268,396
Property, plant and equipment, net	3,284,030	2,861,756
Other assets	'	'
Regulatory assets	290,415	324,081
Derivative instruments	41,056	48,949
Other	17,068	14,759
Total other assets	348,539	387,789
Total assets	4,017,070	3,517,941
Current liabilities	'	'
Short-term debt	84,000	9,000
Borrowings under utility money pool arrangement	38,000	0
Accounts payable	143,879	141,327
Accounts payable to affiliates	15,387	12,363
Regulatory liabilities	83,759	75,891
Taxes accrued	23,584	19,380
Accrued interest	16,883	15,104
Dividends payable	18,082	16,773
Derivative instruments	3,583	3,601
Other	75,355	31,084
Total current liabilities	502,512	324,523
Deferred credits and other liabilities	'	'
Deferred income taxes	757,778	662,201
Regulatory liabilities	81,504	91,815
Asset retirement obligations	19,375	17,607
Derivative instruments	34,207	37,790
Pension and employee benefit obligations	55,087	97,273
Other	3,051	6,093
Total deferred credits and other liabilities	951,002	912,779
Commitments and Contingencies	'	'
Capitalization	'	'
Long-term debt	1,199,865	1,103,684
Common stock b 200 shares authorized of $1.00 par value; 100 shares outstanding at Dec. 31, 2013 and 2012, respectively	0	0
Additional paid in capital	1,005,463	843,186
Retained earnings	359,389	335,101
Accumulated other comprehensive loss	-1,161	-1,332
Total common stockholderbs equity	1,363,691	1,176,955
Total liabilities and equity	$4,017,070	$3,517,941

BALANCE_SHEETS_Parenthetical

BALANCE SHEETS (Parenthetical) (USD $)	Dec. 31, 2013	Dec. 31, 2012
Capitalization, Long-term Debt and Equity [Abstract]	'	'
Common stock, shares authorized (in shares)	200	200
Common stock, par value (in dollars per share)	$1	$1
Common stock, shares outstanding (in shares)	100	100

STATEMENTS_OF_COMPREHENSIVE_IN

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	$95,177	$106,369	$89,901
Derivative instruments:	'	'	'
Reclassification of losses to net income, net of tax of $97, $97 and $98, respectively	171	172	171
Other comprehensive income	171	172	171
Comprehensive income	$95,348	$106,541	$90,072

STATEMENTS_OF_COMPREHENSIVE_IN1

STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Derivative instruments:	'	'	'
Reclassification of losses to net income, tax	$97	$97	$98

STATEMENTS_OF_CAPITALIZATION

STATEMENTS OF CAPITALIZATION (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Long-Term Debt	'	'
Unamortized (discount) premium	($135)	$3,684
Total long-term debt, including current maturities	1,199,865	1,103,684
Less: current maturities	0	0
Long-term debt	1,199,865	1,103,684
Common Stockholder's Equity	'	'
Common stock b 200 shares authorized of $1.00 par value; 100 shares outstanding at Dec. 31, 2013 and 2012, respectively	0	0
Additional paid in capital	1,005,463	843,186
Retained earnings	359,389	335,101
Accumulated other comprehensive loss	-1,161	-1,332
Total common stockholderbs equity	1,363,691	1,176,955
First Mortgage Bonds | Series Due Aug. 15, 2041	'	'
Schedule of Capitalization, Long-term Debt [Line Items]	'	'
Debt instrument, interest rate stated percentage (in hundredths)	4.50%	'
Long-Term Debt	'	'
Long-term debt, gross	400,000	300,000
Debt Instrument, Maturity Date	15-Aug-41	'
Unsecured Senior Notes | Senior E Due Oct. 1, 2016	'	'
Schedule of Capitalization, Long-term Debt [Line Items]	'	'
Debt instrument, interest rate stated percentage (in hundredths)	5.60%	'
Long-Term Debt	'	'
Long-term debt, gross	200,000	200,000
Debt Instrument, Maturity Date	1-Oct-16	'
Unsecured Senior Notes | Senior G Due Dec. 1, 2018	'	'
Schedule of Capitalization, Long-term Debt [Line Items]	'	'
Debt instrument, interest rate stated percentage (in hundredths)	8.75%	'
Long-Term Debt	'	'
Long-term debt, gross	250,000	250,000
Debt Instrument, Maturity Date	1-Dec-18	'
Unsecured Senior Notes | Senior C and D Due Oct. 1, 2033	'	'
Schedule of Capitalization, Long-term Debt [Line Items]	'	'
Debt instrument, interest rate stated percentage (in hundredths)	6.00%	'
Long-Term Debt	'	'
Long-term debt, gross	100,000	100,000
Debt Instrument, Maturity Date	1-Oct-33	'
Unsecured Senior Notes | Senior F Due Oct. 1, 2036	'	'
Schedule of Capitalization, Long-term Debt [Line Items]	'	'
Debt instrument, interest rate stated percentage (in hundredths)	6.00%	'
Long-Term Debt	'	'
Long-term debt, gross	$250,000	$250,000
Debt Instrument, Maturity Date	1-Oct-36	'

STATEMENTS_OF_CAPITALIZATION_P

STATEMENTS OF CAPITALIZATION (Parenthetical) (USD $)	Dec. 31, 2013	Dec. 31, 2012	Aug. 31, 2013	Jun. 30, 2012	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2013
			First Mortgage Bonds	First Mortgage Bonds	First Mortgage Bonds	Unsecured Senior Notes	Unsecured Senior Notes	Unsecured Senior Notes	Unsecured Senior Notes
			Series Due Aug. 15, 2041	Series Due Aug. 15, 2041	Series Due Aug. 15, 2041	Senior E Due Oct. 1, 2016	Senior G Due Dec. 1, 2018	Senior C and D Due Oct. 1, 2033	Senior F Due Oct. 1, 2036
Long-Term Debt	'	'	'	'	'	'	'	'	'
Debt instrument, interest rate stated percentage (in hundredths)	'	'	4.50%	4.50%	4.50%	5.60%	8.75%	6.00%	6.00%
Debt Instrument, Maturity Date	'	'	15-Aug-41	15-Aug-41	15-Aug-41	1-Oct-16	1-Dec-18	1-Oct-33	1-Oct-36
Common Stockholder's Equity	'	'	'	'	'	'	'	'	'
Common stock, shares authorized (in shares)	200	200	'	'	'	'	'	'	'
Common stock, par value (in dollars per share)	$1	$1	'	'	'	'	'	'	'
Common stock, shares outstanding (in shares)	100	100	'	'	'	'	'	'	'

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 — SPS is principally engaged in the regulated generation, purchase, transmission, distribution and sale of electricity. SPS’ financial statements and disclosures are presented in accordance with GAAP.  All of SPS’ 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.
	Variable Interest Entities — SPS evaluates its arrangements and contracts with other entities, including but not limited to, PPAs and fuel contracts to determine if the other party is a variable interest entity, if SPS has a variable interest and if SPS is the primary beneficiary. SPS 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 SPS 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, SPS 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 — SPS 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, SPS 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 SPS’ 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.  SPS presents its revenues net of any excise or other fiduciary-type taxes or fees.
	SPS participates in SPP.  The revenues and charges from SPP related to serving retail and wholesale electric customers comprising the native load of SPS are recorded on a net basis within cost of sales.  Revenues and charges for short-term wholesale sales of excess energy transacted through SPP are recorded on a gross basis in electric revenues and cost of sales.
	SPS has various rate-adjustment mechanisms in place that provide for the recovery of electric fuel costs and purchased energy costs. These cost-adjustment tariffs may increase or decrease the level of revenue collected from customers and are revised periodically for differences between the total amount collected under the clauses and the costs incurred.  When applicable, under governing regulatory commission rate orders, fuel cost over-recoveries (the excess of fuel revenue billed to customers over fuel costs incurred) are deferred as regulatory liabilities and under-recoveries (the excess of fuel costs incurred over fuel revenues billed to customers) are deferred as regulatory assets.
	Conservation Programs — SPS has implemented programs in its jurisdictions to assist customers in conserving energy and reducing peak demand on the electric system.  These programs include commercial process efficiency and lighting updates, as well as residential rebates for participation in air conditioner interruption and energy-efficient appliances.
	The costs incurred for some DSM programs are deferred as permitted by the applicable regulatory jurisdiction. For those programs, costs are deferred if it is probable future revenue will be provided to permit recovery of the incurred cost. For incentive programs designed to allow adjustments of future rates for recovery of lost margins and/or conservation performance incentives, recorded revenues are limited to those amounts expected to be collected within 24 months following the end of the annual period in which they are earned.  SPS recovers approved conservation program costs in base rate revenue or through a rider.
	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.
	SPS 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 2.6, 2.7 and 2.7 percent for the years ended Dec. 31, 2013, 2012 and 2011, respectively.
	Leases — SPS evaluates a variety of contracts for lease classification at inception, including PPAs and 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 SPS’ rate base for establishing utility service rates.
	AROs — SPS 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.
	SPS 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.
	Income Taxes — SPS 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.  SPS defers income taxes for all temporary differences between pretax financial and taxable income, and between the book and tax bases of assets and liabilities. SPS 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 rate making 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.
	SPS 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. SPS recognizes a tax position in its 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.
	SPS reports interest and penalties related to income taxes within the other income and interest charges sections in the statements of income.
	Xcel Energy Inc. and its subsidiaries, including SPS, 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 — SPS uses derivative instruments in connection with its utility commodity price, interest rate, short-term wholesale and commodity trading 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 balance sheets at fair value as derivative instruments.  This includes certain instruments used to mitigate market risk for the utility operations including transmission in organized markets and all instruments related to the commodity trading 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 expected recovery of derivative instrument settlements through fuel and purchased energy cost recovery mechanisms.
	Gains or losses on commodity trading transactions are recorded as a component of electric operating revenues.  Interest rate hedging transactions are recorded as a component of interest expense. For further information on derivatives entered to mitigate market risk associated with transmission in organized markets, 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 — SPS 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.
	SPS 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.  None of the contracts entered into within the commodity trading operations qualify for a normal purchases and normal sales designation.
	See Note 9 for further discussion of SPS’ risk management and derivative activities.
	Commodity Trading Operations — All applicable gains and losses related to commodity trading activities, whether or not settled physically, are shown on a net basis in electric operating revenues in the statements of income.
	Pursuant to the JOA approved by the FERC, some of the commodity trading margins from SPS are apportioned to NSP-Minnesota and PSCo. Commodity trading activities are not associated with energy produced from SPS’ generation assets or energy and capacity purchased to serve native load.  Commodity trading contracts are recorded at fair market value and commodity trading results include the impact of all margin-sharing mechanisms.  See Note 9 for further discussion.
	Fair Value Measurements — SPS presents cash equivalents, interest rate derivatives and commodity derivatives at estimated fair values in its 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, SPS 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 — SPS 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. SPS 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.  SPS 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.  As a result of certain state regulatory orders, SPS reduces recoverable fuel costs for the cost of certain RECs and records that cost as a regulatory asset when the amount is recoverable in future rates.  Sales of RECs that are purchased or acquired in the course of generation are recorded in electric utility operating revenues on a gross basis.  The cost of these RECs, related transaction costs, and amounts credited to customers under margin-sharing mechanisms are recorded in electric fuel and purchased power expense.
	Emission Allowances — Emission allowances, including the annual SO2 and NOx emission allowance entitlement received from the EPA, are recorded at cost plus associated broker commission fees.  SPS 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 statements of cash flows.
	Environmental Costs — Environmental costs are recorded when it is probable SPS 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 SPS’ 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 — SPS 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 — SPS 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 SPS is released from risk under the guarantee.  See Note 11 for specific details of issued guarantees.
	Segment Information - SPS has only one reportable segment.  SPS is a wholly owned subsidiary of Xcel Energy Inc. and operates in the regulated electric utility industry providing wholesale and retail electric service in the states of Texas and New Mexico.  Operating results from the regulated electric utility segment serve as the primary basis for the chief operating decision maker to evaluate the performance of SPS.
	Subsequent Events — Management has evaluated the impact of events occurring after Dec. 31, 2013 up to the date of issuance of these 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 balance sheets, and were effective for annual reporting periods beginning on or after Jan. 1, 2013, and interim periods within those annual reporting periods.  SPS implemented the disclosure guidance effective Jan. 1, 2013, and the implementation did not have a material impact on its 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 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.  SPS implemented the disclosure guidance effective Jan. 1, 2013, and the implementation did not have a material impact on its 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
	Accounts receivable	$	76,426		$	66,789
	Less allowance for bad debts	(5,475		)	(4,722		)
		$	70,951		$	62,067
	(Thousands of Dollars)	Dec. 31, 2013			Dec. 31, 2012
	Inventories
	Materials and supplies	$	21,600		$	18,129
	Fuel	15,538			13,208
		$	37,138		$	31,337
	(Thousands of Dollars)	Dec. 31, 2013			Dec. 31, 2012
	Property, plant and equipment, net
	Electric plant	$	4,714,398		$	4,379,208
	Construction work in progress	388,323			237,136
	Total property, plant and equipment	5,102,721			4,616,344
	Less accumulated depreciation	(1,818,691		)	(1,754,588		)
		$	3,284,030		$	2,861,756

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
	Short-Term Borrowings
	Money Pool — Xcel Energy Inc. and its utility subsidiaries have established a money pool arrangement that allows for short-term investments in and borrowings between the utility subsidiaries. Xcel Energy Inc. may make investments in the utility subsidiaries at market-based interest rates; however, the money pool arrangement does not allow the utility subsidiaries to make investments in Xcel Energy Inc. Money pool borrowings for SPS were as follows:
	(Amounts in Millions, Except Interest Rates)		Three Months Ended Dec. 31, 2013
	Borrowing limit		$	100
	Amount outstanding at period end		38
	Average amount outstanding		65
	Maximum amount outstanding		100
	Weighted average interest rate, computed on a daily basis		0.18		%
	Weighted average interest rate at period end		0.25
	(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		$	100			$	100			$	100
	Amount outstanding at period end		38				—				5
	Average amount outstanding		46				10				12
	Maximum amount outstanding		100				63				71
	Weighted average interest rate, computed on a daily basis		0.15		%		0.33		%		0.35		%
	Weighted average interest rate at end of period		0.25				N/A				0.35
	Commercial Paper — SPS meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under its credit facility. Commercial paper outstanding for SPS was as follows:
	(Amounts in Millions, Except Interest Rates)		Three Months Ended Dec. 31, 2013
	Borrowing limit		$	300
	Amount outstanding at period end		84
	Average amount outstanding		60
	Maximum amount outstanding		121
	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		$	300			$	300			$	300
	Amount outstanding at period end		84				9				—
	Average amount outstanding		32				18				54
	Maximum amount outstanding		140				106				161
	Weighted average interest rate, computed on a daily basis		0.3		%		0.39		%		0.37		%
	Weighted average interest rate at end of period		0.27				0.36				N/A
	Letters of Credit — SPS may use letters of credit, generally with terms of one-year, to provide financial guarantees for certain operating obligations. At Dec. 31, 2013, there were $25.5 million of letters of credit outstanding under the credit facility. At Dec. 31, 2012, there were no letters of credit outstanding under the credit facility. The contract amounts of these letters of credit approximate their fair value and are subject to fees.
	Credit Facility — In order to use its commercial paper program to fulfill short-term funding needs, SPS 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.
	SPS has a five-year credit agreement with a syndicate of banks. The total size of the credit facility is $300 million and the credit facility terminates in July 2017.
	SPS has the right to request an extension of the revolving termination date for two additional one-year periods. All extension requests are subject to majority bank group approval.
	Other features of SPS’ credit facility include:
	•	The credit facility may be increased by up to $50 million.
	•	The credit facility has a financial covenant requiring that SPS’ debt-to-total capitalization ratio be less than or equal to 65 percent. SPS was in compliance as its debt-to-total capitalization ratio was 49 percent at Dec. 31, 2013. If SPS 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 SPS will be in default on its borrowings under the facility if SPS or any of its future significant subsidiaries whose total assets exceed 15 percent of SPS’ 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, SPS had the following committed credit facility available (in millions):
	Credit Facility (a)				Drawn (b)				Available
	$	300			$	109.5			$	190.5
	(a)	Credit facility expires in July 2017.
	(b)	Includes outstanding commercial paper and letters of credit.
	All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity under the credit facility. SPS had no direct advances on the credit facility outstanding at Dec. 31, 2013 and 2012.
	Long-Term Borrowings and Other Financing Instruments
	Generally, all real and personal property of SPS is subject to the lien of its first mortgage indenture. Debt premiums, discounts and expenses are amortized over the life of the related debt. The premiums, discounts and expenses associated with refinanced debt are deferred and amortized over the life of the related new issuance, in accordance with regulatory guidelines.
	In August 2013, SPS issued $100 million of 4.50 percent first mortgage bonds due Aug. 15, 2041. Including the $300 million of this series previously issued, total principal outstanding for this series is $400 million. In June 2012, SPS issued an additional $100 million of its 4.50 percent first mortgage bonds due Aug. 15, 2041.
	During the next five years, SPS has long-term debt maturities of $200 million and $250 million due in 2016 and 2018, respectively.
	Deferred Financing Costs — Other assets included deferred financing costs of approximately $10.3 million and $9.7 million, net of amortization, at Dec. 31, 2013 and 2012, respectively.  SPS is amortizing these financing costs over the remaining maturity periods of the related debt.
	Dividend Restrictions — SPS’ 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 SPS is imposed by its state regulatory commissions. SPS’ state regulatory commissions indirectly limit the amount of dividends that SPS can pay Xcel Energy Inc. by requiring an equity-to-total capitalization ratio (excluding short-term debt) between 45.0 percent and 55.0 percent. In addition, SPS may not pay a dividend that would cause it to lose its investment grade bond rating.  SPS’ equity-to-total capitalization ratio (excluding short-term debt) was 53.2 percent at Dec. 31, 2013 and $359 million in retained earnings was not restricted.

Preferred_Stock

Preferred Stock	12 Months Ended
	Dec. 31, 2013
Equity [Abstract]	'
Preferred Stock	'
	Preferred Stock
	SPS has authorized the issuance of preferred stock.
	Preferred	Par Value		Preferred
	Shares			Shares
	Authorized			Outstanding
	10,000,000	$	1	None

Income_Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2013
Income Tax Disclosure [Abstract]	'
Income Taxes	'
	Income Taxes
	Federal Audit — SPS 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.  SPS 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 — SPS is a member of the Xcel Energy affiliated group that files consolidated state income tax returns.  As of Dec. 31, 2013, SPS’ earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations is 2008. There are currently no 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	$	1.2			$	0.2
	Unrecognized tax benefit — Temporary tax positions	2.9				3.7
	Total unrecognized tax benefit	$	4.1			$	3.9
	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	$	3.9			$	4.8			$	4.3
	Additions based on tax positions related to the current year	1.6				1.1				1.5
	Reductions based on tax positions related to the current year	—				(1.6		)		(0.2		)
	Additions for tax positions of prior years	3.1				0.8				2.5
	Reductions for tax positions of prior years	(0.3		)		(1.2		)		(0.3		)
	Settlements with taxing authorities	(4.2		)		—				(3.0		)
	Balance at Dec. 31	$	4.1			$	3.9			$	4.8
	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	$	(2.4	)		$	(2.0	)
	It is reasonably possible that SPS’ amount of unrecognized tax benefits could significantly change in the next 12 months as the IRS audit progresses and state audits resume.  As the IRS examination moves closer to completion, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $2 million.
	The payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryforwards.  The payables for interest related to unrecognized tax benefits at Dec. 31, 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 SPS had adopted certain utility-specific guidance previously issued by the IRS, the issuance is not expected to have a material impact on its 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	168.7			158
	Federal tax credit carryforwards	1.7			1.3
	State NOL carryforwards	23.6			21
	The federal carryforward periods expire between 2021 and 2033.  The state carryforward periods expire between 2014 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	2			2.2			2.9
	Change in unrecognized tax benefits	0.7			—			—
	Regulatory differences — utility plant items	(1.1	)		(0.4	)		(0.1	)
	Tax credits recognized	(0.4	)		(0.2	)		(0.3	)
	Other, net	(0.1	)		0.3			0.5
	Effective income tax rate	36.1	%		36.9	%		38	%
	The components of income tax expense for the years ending Dec. 31 were:
	(Thousands of Dollars)	2013				2012				2011
	Current federal tax expense (benefit)	$	14,947			$	6,549			$	(1,993	)
	Current state tax expense	2,943				2,712				3,287
	Current change in unrecognized tax benefit	(263		)		(824		)		(1,394		)
	Deferred federal tax expense	33,489				50,189				50,903
	Deferred state tax expense	1,754				3,069				3,240
	Deferred change in unrecognized tax expense	1,232				861				1,365
	Deferred investment tax credits	(341		)		(327		)		(275		)
	Total income tax expense	$	53,761			$	62,229			$	55,133
	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	$	38,333			$	55,749			$	56,181
	Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities	(1,761		)		(1,533		)		(575		)
	Tax expense allocated to other comprehensive income	(97		)		(97		)		(98		)
	Deferred tax expense	$	36,475			$	54,119			$	55,508
	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:
	Differences between book and tax bases of property	$	705,416			$	654,259
	Employee benefits	52,081				51,394
	Other	30,066				24,034
	Total deferred tax liabilities	$	787,563			$	729,687
Deferred tax assets:
NOL carryforward	$	61,330			$	59,562
Rate refund	17,192				2,911
Unbilled revenue - fuel costs	13,316				10,555
Regulatory liabilities	9,724				6,176
Deferred fuel costs	6,877				11,952
Other	6,708				4,448
Total deferred tax assets	$	115,147			$	95,604
Net deferred tax liability	$	672,416			$	634,083

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, SPS accounts for its participation in, and related costs of, pension and other postretirement benefit plans sponsored by Xcel Energy Inc. as multiple employer plans. SPS is responsible for its share of cash contributions, plan costs and obligations and is entitled to its share of plan assets; accordingly, SPS 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 SPS employees.
	Xcel Energy, which includes SPS, offers various benefit plans to its employees. Approximately 65 percent of employees that receive benefits are represented by several local labor unions under several collective-bargaining agreements. At Dec. 31, 2013, SPS had 832 bargaining employees covered under a collective-bargaining agreement, which expires in October 2014.
	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 SPS, 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 SPS’ 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 $2.8 million and $3.3 million were attributable to SPS. 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 $0.3 million and $0.3 million were attributable to SPS. Benefits for these unfunded plans are paid out of Xcel Energy’s consolidated operating cash flows.
	Xcel Energy Inc. and SPS 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 were below the assumed levels of 6.49 percent in 2013 and above the assumed levels of 6.68 percent and 6.80 percent in 2012 and 2011, respectively. Xcel Energy Inc. and SPS continually review the pension assumptions. In 2014, SPS’ expected investment-return assumption is 6.90 percent.
	The assets are invested in a portfolio according to Xcel Energy Inc.’s and SPS’ 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 SPS:
			2013			2012
	Domestic and international equity securities		29	%		21	%
	Long-duration fixed income and interest rate swap securities		36			50
	Short-to-intermediate term fixed income securities		14			8
	Alternative investments		19			19
	Cash		2			2
	Total		100	%		100	%
	The ongoing investment strategy is based on plan-specific investment recommendations that seek to minimize potential investment and interest rate risk as a plan’s funded status increases over time. The investment recommendations result in a greater percentage of long-duration fixed income securities being allocated to specific plans having relatively higher funded status ratios, and a greater percentage of growth assets being allocated to plans having relatively lower funded status ratios. The aggregate projected asset allocation presented in the table above for the master pension trust results from the plan-specific strategies.
	Pension Plan Assets
	The following tables present, for each of the fair value hierarchy levels, SPS’ 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		$	17,354			$	—			$	—		$	17,354
	Derivatives		—				4,200				—			4,200
	Government securities		—				26,649				—			26,649
	Corporate bonds		—				79,635				—			79,635
	Asset-backed securities		—				889				—			889
	Mortgage-backed securities		—				1,939				—			1,939
	Common stock		12,813				—				—			12,813
	Private equity investments		—				—				18,222			18,222
	Commingled funds		—				223,322				—			223,322
	Real estate		—				—				5,755			5,755
	Securities lending collateral obligation and other		—				2,615				—			2,615
	Total		$	30,167			$	339,249			$	23,977		$	393,393
			Dec. 31, 2012
	(Thousands of Dollars)		Level 1				Level 2				Level 3			Total
	Cash equivalents		$	26,765			$	—			$	—		$	26,765
	Derivatives		—				1,388				—			1,388
	Government securities		—				33,676				—			33,676
	Corporate bonds		—				95,726				—			95,726
	Asset-backed securities		—				—				1,755			1,755
	Mortgage-backed securities		—				—				4,331			4,331
	Common stock		7,762				—				—			7,762
	Private equity investments		—				—				17,049			17,049
	Commingled funds		—				183,957				—			183,957
	Real estate		—				—				6,969			6,969
	Securities lending collateral obligation and other		—				(3,240		)		—			(3,240		)
	Total		$	34,527			$	311,507			$	30,104		$	376,138
	The following tables present the changes in SPS’ Level 3 pension plan assets for the years ended Dec. 31, 2013, 2012 and 2011:
	(Thousands of Dollars)		Jan. 1, 2013				Net Realized Gains (Losses)				Net Unrealized Gains (Losses)			Purchases,			Transfers Out of Level 3 (a)			Dec. 31, 2013
														Issuances and Settlements, Net
	Asset-backed securities		$	1,755			$	—			$	—		$	—		$	(1,755	)	$	—
	Mortgage-backed securities		4,331				—				—			—			(4,331		)	—
	Private equity investments		17,049				2,630				(1,055		)	(402		)	—			18,222
Real estate		6,969				(322		)		1,475			1,128			(3,495		)	5,755
Total		$	30,104			$	2,308			$	420		$	726		$	(9,581	)	$	23,977
(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 Gains (Losses)				Net Unrealized Gains (Losses)			Purchases,			Transfers Out of Level 3			Dec. 31, 2012
													Issuances and Settlements, Net
Asset-backed securities		$	4,018			$	531			$	(741	)	$	(2,053	)	$	—		$	1,755
Mortgage-backed securities		7,907				245				(265		)	(3,556		)	—			4,331
Private equity investments		16,159				1,886				(2,296		)	1,300			—			17,049
Real estate		3,586				2				551			2,830			—			6,969
Total		$	31,670			$	2,664			$	(2,751	)	$	(1,479	)	$	—		$	30,104
(Thousands of Dollars)		Jan. 1, 2011				Net Realized Gains (Losses)				Net Unrealized Gains (Losses)			Purchases,			Transfers Out of Level 3			Dec. 31, 2011
													Issuances and Settlements, Net
Asset-backed securities		$	3,450			$	328			$	(355	)	$	595		$	—		$	4,018
Mortgage-backed securities		11,060				170				(865		)	(2,458		)	—			7,907
Private equity investments		11,464				401				1,300			2,994			—			16,159
Real estate		10,132				(61		)		3,131			(9,616		)	—			3,586
Total		$	36,106			$	838			$	3,211		$	(8,485	)	$	—		$	31,670
Benefit Obligations — A comparison of the actuarially computed pension benefit obligation and plan assets for SPS is presented in the following table:
(Thousands of Dollars)		2013				2012
Accumulated Benefit Obligation at Dec. 31		$	402,509			$	416,808
Change in Projected Benefit Obligation:
Obligation at Jan. 1		$	454,184			$	403,367
Service cost		9,615				8,520
Interest cost		17,908				19,697
Plan amendments		—				98
Actuarial (gain) loss		(27,185		)		45,881
Transfer from other plan		3,625				—
Benefit payments		(23,840		)		(23,379		)
Obligation at Dec. 31		$	434,307			$	454,184
(Thousands of Dollars)		2013				2012
Change in Fair Value of Plan Assets:
Fair value of plan assets at Jan. 1		$	376,138			$	350,054
Actual return on plan assets		15,455				36,403
Employer contributions		22,015				13,060
Transfer from other plan		3,625				—
Benefit payments		(23,840		)		(23,379		)
Fair value of plan assets at Dec. 31		$	393,393			$	376,138
(Thousands of Dollars)		2013				2012
Funded Status of Plans at Dec. 31:
Funded status (a)		$	(40,914	)		$	(78,046	)
(a)	Amounts are recognized in noncurrent liabilities on SPS’ balance sheets.
(Thousands of Dollars)		2013				2012
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:
Net loss		$	208,594			$	244,412
Prior service cost		93				963
Total		$	208,687			$	245,375
(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		$	15,843			$	14,877
Noncurrent regulatory assets		192,844				230,498
Total		$	208,687			$	245,375
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 $4.4 million was attributable to SPS;
•	In 2013, contributions of $192.4 million were made across four of Xcel Energy’s pension plans, of which $22.0 million was attributable to SPS;
•	In 2012, contributions of $198.1 million were made across four of Xcel Energy’s pension plans, of which $13.1 million was attributable to SPS;
•	In 2011, contributions of $137.3 million were made across three of Xcel Energy’s pension plans, of which $5.2 million was attributable to SPS;
•	For future years, Xcel Energy and SPS anticipate contributions will be made as necessary.
Plan Amendments —Xcel Energy, which includes SPS, amended the plan in 2012 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 SPS also modified the benefit formula for nonbargaining and bargaining new hires beginning in 2012 to a reduced benefit level.
Benefit Costs — The components of SPS’ net periodic pension cost were:
(Thousands of Dollars)		2013				2012				2011
Service cost		$	9,615			$	8,520			$	7,690
Interest cost		17,908				19,697				20,036
Expected return on plan assets		(23,970		)		(24,928		)		(26,316		)
Amortization of prior service cost		870				1,438				1,505
Amortization of net loss		17,148				12,897				9,046
Net periodic pension cost		$	21,571			$	17,624			$	11,961
Costs not recognized due to effects of regulation		(1,269		)		(4,300		)		(2,300		)
Net benefit cost recognized for financial reporting		$	20,302			$	13,324			$	9,661
		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		6.49			6.68			6.8
In addition to the benefit costs in the table above, for the pension plans sponsored by Xcel Energy Inc., costs are allocated to SPS based on Xcel Energy Services Inc. employees’ labor costs. Amounts allocated to SPS were $4.9 million, $4.1 million and $2.9 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 6.90 percent. The cost calculation uses a market-related valuation of pension assets. Xcel Energy, including SPS, 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 SPS, maintains 401(k) and other defined contribution plans that cover substantially all employees. The expense to these plans for SPS was approximately $2.4 million in 2013, $2.3 million in 2012 and $2.0 million in 2011.
Postretirement Health Care Benefits
Xcel Energy, which includes SPS, has a contributory health and welfare benefit plan that provides health care and death benefits to certain retirees. Xcel Energy discontinued contributing toward health care benefits for former NCE, which includes SPS, nonbargaining employees retiring after June 30, 2003. Employees of NCE who retired in 2002 continue to receive employer-subsidized health care benefits. Nonbargaining employees of the former NCE who retired after 1998, bargaining employees of the former NCE who retired after 1999 and nonbargaining employees of NCE who retired after June 30, 2003, are eligible to participate in the Xcel Energy health care program with no employer subsidy.
In 1993, Xcel Energy Inc. and SPS 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. SPS is required to fund postretirement benefit costs for Texas and New Mexico jurisdictional amounts collected in rates. 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 SPS 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 SPS’ return, liquidity and diversification objectives to provide a source of funding for plan obligations and minimize the necessity of contributions to the plan, within appropriate levels of risk. The principal mechanism for achieving these objectives is the projected allocation of assets to selected asset classes, given the long-term risk, return, correlation and liquidity characteristics of each particular asset class. There were no significant concentrations of risk in any particular industry, index, or entity. Market volatility can impact even well-diversified portfolios and significantly affect the return levels achieved by postretirement health care assets in any year.
The following tables present, for each of the fair value hierarchy levels, SPS’ 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		$	1,941			$	—			$	—		$	1,941
Derivatives		—				(38		)		—			(38		)
Government securities		—				5,549				—			5,549
Insurance contracts		—				5,016				—			5,016
Corporate bonds		—				4,926				—			4,926
Asset-backed securities		—				319				—			319
Mortgage-backed securities		—				2,303				—			2,303
Commingled funds		—				28,331				—			28,331
Other		—				(1,609		)		—			(1,609		)
Total		$	1,941			$	44,797			$	—		$	46,738
		Dec. 31, 2012
(Thousands of Dollars)		Level 1				Level 2				Level 3			Total
Cash equivalents		$	8,774			$	—			$	—		$	8,774
Government securities		—				7,061				—			7,061
Insurance contracts		—				4,807				—			4,807
Corporate bonds		—				4,211				—			4,211
Asset-backed securities		—				—				73			73
Mortgage-backed securities		—				—				3,841			3,841
Commingled funds		—				21,958				—			21,958
Other		—				(4,503		)		—			(4,503		)
Total		$	8,774			$	33,534			$	3,914		$	46,222
The following tables present the changes in SPS’ Level 3 postretirement benefit plan assets for the years ended Dec. 31, 2013, 2012 and 2011:
(Thousands of Dollars)		Jan. 1, 2013				Net Realized Gains (Losses)				Net Unrealized Gains (Losses)			Purchases,			Transfers Out of Level 3 (a)			Dec. 31, 2013
													Issuances and Settlements, Net
Asset-backed securities		$	73			$	—			$	—		$	—		$	(73	)	$	—
Mortgage-backed securities		3,841				—				—			—			(3,841		)	—
Total		$	3,914			$	—			$	—		$	—		$	(3,914	)	$	—
(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 Gains (Losses)				Net Unrealized Gains (Losses)			Purchases,			Transfers Out of Level 3			Dec. 31, 2012
													Issuances and Settlements, Net
Asset-backed securities		$	730			$	(32	)		$	179		$	(804	)	$	—		$	73
Mortgage-backed securities		2,535				(70		)		377			999			—			3,841
Total		$	3,265			$	(102	)		$	556		$	195		$	—		$	3,914
(Thousands of Dollars)		Jan. 1, 2011				Net Realized Gains (Losses)				Net Unrealized Gains (Losses)			Purchases,			Transfers Out of Level 3			Dec. 31, 2011
													Issuances and Settlements, Net
Asset-backed securities		$	245			$	(2	)		$	(101	)	$	588		$	—		$	730
Mortgage-backed securities		1,820				(157		)		194			678			—			2,535
Total		$	2,065			$	(159	)		$	93		$	1,266		$	—		$	3,265
Benefit Obligations — A comparison of the actuarially computed benefit obligation and plan assets for SPS is presented in the following table:
(Thousands of Dollars)		2013				2012
Change in Projected Benefit Obligation:
Obligation at Jan. 1		$	59,260			$	55,165
Service cost		1,368				1,259
Interest cost		2,352				2,831
Medicare subsidy reimbursements		63				404
Plan amendments		—				(4,334		)
Plan participants’ contributions		698				2,004
Actuarial (gain) loss		(5,215		)		7,120
Benefit payments		(3,544		)		(5,189		)
Obligation at Dec. 31		$	54,982			$	59,260
(Thousands of Dollars)		2013				2012
Change in Fair Value of Plan Assets:
Fair value of plan assets at Jan. 1		$	46,222			$	39,679
Actual return on plan assets		3,228				5,375
Plan participants’ contributions		698				2,004
Employer contributions		134				4,353
Benefit payments		(3,544		)		(5,189		)
Fair value of plan assets at Dec. 31		$	46,738			$	46,222
(Thousands of Dollars)		2013				2012
Funded Status of Plans at Dec. 31:
Funded status (a)		$	(8,244	)		$	(13,038	)
(a)	Amounts are recognized in noncurrent liabilities on SPS’ balance sheet.
(Thousands of Dollars)		2013				2012
Amounts Not Yet Recognized as Components of Net Periodic Benefit Credit:
Net gain		$	(5,344	)		$	(90	)
Prior service credit		(3,833		)		(4,317		)
Transition obligations		—				—
Total		$	(9,177	)		$	(4,407	)
(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 liabilities		$	(319	)		$	(954	)
Noncurrent regulatory liabilities		(8,858		)		(3,453		)
Total		$	(9,177	)		$	(4,407	)
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 SPS 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 SPS:
		One-Percentage Point
(Thousands of Dollars)		Increase				Decrease
APBO		$	5,684			$	(4,763	)
Service and interest components		368				(290		)
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 SPS, contributed $17.6 million, $47.1 million and $49.0 million during 2013, 2012 and 2011, respectively, of which $0.1 million, $4.4 million and $3.6 million were attributable to SPS. Xcel Energy expects to contribute approximately $13.3 million during 2014, of which amounts attributable to SPS will be zero.
Plan Amendments — The 2012 decrease of the projected Xcel Energy and SPS 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 SPS’ net periodic postretirement benefit cost were:
(Thousands of Dollars)		2013				2012				2011
Service cost		$	1,368			$	1,259			$	1,092
Interest cost		2,352				2,831				2,722
Expected return on plan assets		(3,183		)		(2,701		)		(3,006		)
Amortization of transition obligation		—				1,545				1,669
Amortization of prior service credit		(484		)		(148		)		(51		)
Amortization of net (gain) loss		(6		)		1,256				855
Net periodic postretirement benefit cost		$	47			$	4,042			$	3,281
		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 SPS based on Xcel Energy Services Inc. employees’ labor costs.
Projected Benefit Payments — The following table lists SPS’ projected benefit payments for the pension and postretirement benefit plans:
(Thousands of Dollars)		Projected				Gross Projected				Expected			Net Projected
		Pension Benefit				Postretirement				Medicare Part D			Postretirement
		Payments				Health Care				Subsidies			Health Care
						Benefit Payments							Benefit Payments
2014		$	26,265			$	3,285			$	33		$	3,252
2015		27,361				3,450				36			3,414
2016		27,565				3,547				50			3,497
2017		28,738				3,691				52			3,639
2018		29,703				3,582				55			3,527
2019-2023		153,507				17,912				186			17,726

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	$	663		$	379		$	506
	Other nonoperating income	9			36			11
	Insurance policy expense	(532		)	(369		)	(111		)
	Other income, net	$	140		$	46		$	406

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.
	Electric commodity derivatives held by SPS include transmission congestion instruments purchased from SPP, generally referred to as FTRs. FTRs purchased from an RTO are financial instruments that entitle or obligate the holder to monthly revenues or charges based on transmission congestion across a given transmission path.  The value of an FTR is derived from, and designed to offset, the cost of energy congestion, which is caused by overall transmission load and other transmission constraints.  In addition to overall transmission load, congestion is also influenced by the operating schedules of power plants and the consumption of electricity pertinent to a given transmission path.  Unplanned plant outages, scheduled plant maintenance, changes in the relative costs of fuels used in generation, weather and overall changes in demand for electricity can each impact the operating schedules of the power plants on the transmission grid and the value of an FTR.  The valuation process for FTRs utilizes complex iterative modeling to predict the impacts of forecasted changes in these drivers of transmission system congestion on the historical pricing of FTR purchases.
	If forecasted costs of electric transmission congestion increase or decrease for a given FTR path, the value of that particular FTR instrument will likewise increase or decrease.  Given the limited observability of management’s forecasts for several of the inputs to this complex valuation model - including expected plant operating schedules and retail and wholesale demand, fair value measurements for FTRs have been assigned a Level 3.  Non-trading monthly FTR settlements are expected to be recovered through fuel and purchased energy cost recovery mechanisms, and therefore changes in the fair value of the yet to be settled portions of FTRs are deferred as a regulatory asset or liability.  Given this regulatory treatment and the limited magnitude of FTRs relative to the electric utility operations of SPS, the numerous unobservable quantitative inputs to the complex model used for valuation of FTRs are insignificant to the financial statements of SPS.
	Derivative Instruments Fair Value Measurements
	SPS enters into derivative instruments, including forward contracts, for trading purposes and to manage risk in connection with changes in interest rates and electric utility commodity prices.
	Interest Rate Derivatives — SPS may enter 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 $0.2 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.
	Wholesale and Commodity Trading Risk — SPS conducts various wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy and energy-related instruments.  SPS’ risk management policy allows management to conduct these activities within guidelines and limitations as approved by its risk management committee, which is made up of management personnel not directly involved in the activities governed by this policy.
	Commodity Derivatives — SPS enters into derivative instruments to manage variability of future cash flows from changes in commodity prices in its electric utility operations, as well as for trading purposes.  This could include the purchase or sale of energy or energy-related products.  At Dec. 31, 2012, SPS held no commodity derivatives.
	The following table details the gross notional amounts of commodity FTRs at Dec. 31, 2013:
	(Amounts in Thousands) (a)(b)		Dec. 31, 2013
	MWh of electricity		5,989
	(a)	Amounts are not reflective of net positions in the underlying commodities.
	Consideration of Credit Risk and Concentrations — SPS 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 SPS’ 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.
	SPS 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.
	SPS’ most significant concentrations of credit risk with particular entities or industries are contracts with counterparties to its wholesale, trading and non-trading commodity activities.  At Dec. 31, 2013, two of SPS’ 10 most significant counterparties for these activities, comprising $13.5 million or 18 percent of this credit exposure, had investment grade credit ratings from Standard & Poor’s, Moody’s or Fitch Ratings.  Seven of the 10 most significant counterparties, comprising $37.4 million or 51 percent of this credit exposure, were not rated by these agencies, but based on SPS’ internal analysis, had credit quality consistent with investment grade. Another of these significant counterparties, comprising $3.3 million or 5 percent of this credit exposure, had credit quality less than investment grade, based on SPS’ internal analysis.  All 10 of these significant counterparties are municipal or cooperative electric entities, or other utilities.
	Financial Impact of Qualifying Cash Flow Hedges — The impact of qualifying interest rate cash flow hedges on SPS’ accumulated other comprehensive loss, included in the statements of common stockholder’s equity and in the 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		$	(1,332	)	$	(1,504	)	$	(1,675	)
	After-tax net realized losses on derivative transactions reclassified into earnings		171			172			171
	Accumulated other comprehensive loss related to cash flow hedges at Dec. 31		$	(1,161	)	$	(1,332	)	$	(1,504	)
	Pre-tax losses related to interest rate derivatives reclassified from accumulated other comprehensive loss into earnings were $0.3 million for each of the years ended Dec. 31, 2013, 2012 and 2011.
	During the year ended Dec. 31, 2013, pre-tax net gains of $9.9 million of FTRs were reclassified as regulatory assets and liabilities.  The classification as a regulatory asset or liability is based on expected recovery of FTR settlements through fuel and purchased energy cost recovery mechanisms.
	SPS 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, SPS’ 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 Total		Counterparty Netting (b)			Total
	Current derivative assets
	Other derivative instruments:
	Electric commodity		$	—		$	—		$	16,420		$	16,420	$	(6,487	)	$	9,933
	Total current derivative assets		$	—		$	—		$	16,420		$	16,420	$	(6,487	)	9,933
	PPAs (a)																7,893
	Current derivative instruments																$	17,826
	Noncurrent derivative assets
	PPAs (a)																$	41,056
	Noncurrent derivative instruments																$	41,056
	Current derivative liabilities
	Other derivative instruments:
	Electric commodity		$	—		$	—		$	6,487		$	6,487	$	(6,487	)	$	—
	Total current derivative liabilities		$	—		$	—		$	6,487		$	6,487	$	(6,487	)	—
	PPAs (a)																3,583
	Current derivative instruments																$	3,583
	Noncurrent derivative liabilities
	PPAs (a)																$	34,207
	Noncurrent derivative instruments																$	34,207
	(a)	In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, SPS began recording several long-term PPAs at fair value due to accounting requirements related to underlying price adjustments.  As these purchases are recovered through normal regulatory recovery mechanisms in the respective jurisdictions, the changes in fair value for these contracts were offset by regulatory assets and liabilities.  During 2006, SPS qualified these contracts under the normal purchase exception.  Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.
	(b)	SPS 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.  At Dec. 31, 2013, derivative assets and liabilities include no obligations to return cash collateral or rights to reclaim cash collateral. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.
	At Dec. 31, 2012, derivative instruments presented on SPS’ balance sheets consist of amounts related to long-term purchased power agreements.
	The following table presents the changes in Level 3 commodity derivatives for the year ended Dec. 31, 2013:
	(Thousands of Dollars)		2013
	Balance at Jan. 1		$	—
	Purchases		9,933
	Balance at Dec. 31		$	9,933
SPS recognizes transfers between levels as of the beginning of each period.  There were no transfers of amounts between levels for derivative instruments for the year ended Dec. 31, 2013.
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			Fair Value			Carrying			Fair Value
		Amount						Amount
Long-term debt, including current portion		$	1,199,865		$	1,307,035		$	1,103,684		$	1,327,538
The fair value of SPS’ 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

Rate Matters	12 Months Ended
	Dec. 31, 2013
Public Utilities, General Disclosures [Abstract]	'
Rate Matters	'
	Rate Matters
	Pending and Recently Concluded Regulatory Proceedings — PUCT
	Texas 2014 Electric Rate Case — On Jan. 7, 2014, SPS filed a retail electric rate case in Texas with each of its Texas municipalities and the PUCT for a net increase in annual revenue of approximately $52.7 million, or 5.8 percent. The net increase reflects a base rate increase, revenue credits transferred from base rates to rate riders or the fuel clause, and resetting the TCRF to zero when the final base rates become effective, as shown in the following table:
	(Millions of Dollars)		SPS Request
	Base rate increase		$	81.5
	Resetting TCRF		(12.9		)
	Credit to customers for gain on sale to Lubbock moved to a rider		(4.9		)
	Net increase in base revenue		63.7
	Fuel clause offsets		(11.0		)
	Retail customer net bill impact		$	52.7
	The rate filing is based on a HTY ending June 2013, a requested ROE of 10.40 percent, an electric rate base of approximately $1.27 billion and an equity ratio of 53.89 percent. The requested rate increase reflects an increase in depreciation expense of approximately $16 million.
	The PUCT has suspended SPS' proposed rates through Oct. 31, 2014. If the PUCT has not issued a final order by July 11, 2014, then SPS' current rates will not change, but the final rates will be made effective retroactive to July 12, 2014.
	Next steps in the procedural schedule are as follows:
	•	Intervenor testimony — May 22, 2014;
	•	PUCT Staff testimony — May 29, 2014;
	•	Cross-rebuttal testimony — June 12, 2014;
	•	Rebuttal testimony — June 16, 2014;
	•	Evidentiary hearing — June 25, 2014; and
	•	A PUCT decision and implementation of final rates are anticipated in the third quarter of 2014.
	Texas 2012 Electric Rate Case — In November 2012, SPS filed an electric rate case in Texas with the PUCT for an increase in annual revenue of approximately $90.2 million.  The rate filing is based on a historic 12 month test year ended June 30, 2012 (adjusted for known and measurable changes), a requested ROE of 10.65 percent, an electric rate base of $1.15 billion and an equity ratio of 52 percent. In June 2013, the PUCT approved a settlement agreement in which SPS’ base rate increased by $37 million, effective May 1, 2013 and by an additional $13.8 million on Sept. 1, 2013.
	Electric, Purchased Gas and Resource Adjustment Clauses
	TCRF Rider — In November 2013, SPS filed with the PUCT to implement the TCRF for Texas retail customers. The requested increase in revenues is $13 million. The PUCT issued an order allowing the TCRF to go into effect on an interim basis effective Jan. 1, 2014.
	Next steps in the procedural schedule are as follows:
	•	Intervenor testimony — April 17, 2014;
	•	Rebuttal testimony — May 6, 2014; and
	•	Evidentiary hearings — May 15 - May 16, 2014.
	Pending Regulatory Proceedings — NMPRC
	New Mexico 2014 Electric Rate Case — In December 2012, SPS filed an electric rate case in New Mexico with the NMPRC for an increase in annual revenue of approximately $45.9 million effective in 2014.  The rate filing is based on a 2014 forecast test year (FTY), a requested ROE of 10.65 percent, an electric rate base of $479.8 million and an equity ratio of 53.89 percent. In June 2013, SPS revised its requested rate increase to $43.3 million.
	In August 2013, the NMPRC Staff (Staff), the NMAG, the Federal Executive Agencies, the Coalition of Clean Affordable Energy, Occidental Permian, Ltd. and New Mexico Gas Company filed testimony.
	The following table summarizes certain parties’ recommendations from SPS’ revised request:
	(Millions of Dollars)		Staff			NMAG
			Testimony			Testimony
			Aug-13			Aug-13
	SPS revised request		$	43.3		$	43.3
	Rate rider for renewable energy costs (a)		(14.5		)	(8.5		)
	Present revenues (sales growth and weather)		(4.4		)	(6.4		)
	ROE (9.8 percent and 8.63 percent, respectively)		(3.2		)	(8.1		)
	Capital structure		(1.5		)	(1.1		)
	Employee benefits		(2.8		)	(1.8		)
	Reduced recovery for payroll expense		(0.1		)	(0.1		)
	Gain on sale of transmission assets		—			(1.7		)
	Fuel clause revenue		6			—
	Other, net		(5.0		)	(6.6		)
	Recommended rate increase		$	17.8		$	9
	Means of recovery:
	Base revenue		$	8.8		$	(6.0	)
	Rider revenue		7.3			13.3
	Fuel cost adjustment revenue		1.7			1.7
			$	17.8		$	9
	(a)	Adjustments represent recommended deferrals, extended amortizations and moving costs from rider to fuel in base rates.
	In September 2013, SPS filed rebuttal testimony, revising its requested rate increase to $32.5 million, based on updated information and an ROE of 10.25 percent. This reflects a base and fuel increase of $20.9 million, an increase of rider revenue of $12.1 million and a decrease to other of $0.5 million.
	In January 2014, the hearing examiner released her recommended decision. SPS estimates the recommendation reduces the requested rate increase by approximately $6.2 million, resulting in a base revenue increase of $14.7 million. The recommendation proposes an ROE of 9.73 percent, an equity ratio of 53.89 percent, an FTY with certain adjustments and excludes certain employee benefits and other costs. In February 2014, the hearing examiner released a supplemental recommended decision proposing the approval of the requested $12.1 million renewable energy rider revenue recovery. Parties have filed exceptions to the hearing examiner’s recommendations. An NMPRC decision and final rates are expected to be effective in the second quarter of 2014.
	Pending and Recently Concluded Regulatory Proceedings — FERC
	2004 FERC Complaint Case Orders — In August 2013, the FERC issued an order on rehearing related to a 2004 Complaint case brought by Golden Spread Electric Cooperative, Inc. (Golden Spread), a wholesale cooperative customer, and PNM and an Order on Initial Decision in a subsequent 2006 rate case filed by SPS.
	The original Complaint included two key components: 1) PNM’s claim regarding inappropriate allocation of fuel costs and 2) a base rate complaint, including the appropriate demand-related cost allocator. The FERC previously determined that the allocation of fuel costs and the demand-related cost allocator utilized by SPS was appropriate.
	In the August 2013 Orders, the FERC clarified its previous ruling on the allocation of fuel costs and reaffirmed that the refunds in question should only apply to firm requirements customers and not PNM’s contractual load. The FERC also reversed its prior demand-related cost allocator decision. The FERC stated that it had erred in its initial analysis and concluded that the SPS system was a 3CP rather than a 12CP system.
	The pre-tax impact to 2013 earnings from these orders is approximately $36 million. Pending the timing and resolution of this matter, the annual impact to revenues through 2014 could be up to $6 million and decreasing to $4 million on June 1, 2015.
	In September 2013, SPS filed a request for rehearing of the FERC ruling on the CP allocation and refund decisions. SPS asserted that the FERC applied an improper burden of proof and that precedent did not support retroactive refunds. PNM also requested rehearing of the FERC decision not to reverse its prior ruling.
	In October 2013, the FERC issued orders further considering the requests for rehearing. These matters are currently pending the FERC’s action. If unsuccessful in its rehearing request, SPS will have the opportunity to file rate cases with the FERC and its retail jurisdictions seeking to change all customers to a 3CP allocation method.
	Wholesale Rate Complaint — In April 2012, Golden Spread filed a rate complaint alleging that the base ROE included in the SPS production formula rate of 10.25 percent, and the SPS transmission base formula rate ROE of 10.77 percent, are unjust and unreasonable. Golden Spread alleged that the appropriate base ROE is 9.15 percent, or an annual difference of approximately $3.3 million. An additional 50 basis point incentive is added to the base ROE for the transmission formula rate for SPS’ participation in the SPP RTO. Golden Spread is not contesting this transmission incentive.  The FERC has taken no action on this complaint. If granted, the complaint could reduce SPS revenues approximately $3.1 million per year prospectively from the effective date established by the FERC.
	Sale of Texas Transmission Assets — In March 2013, SPS reached an agreement to sell certain segments of SPS’ transmission lines and two related substations to Sharyland. In 2013, SPS received all necessary regulatory approvals for the transaction. On Dec. 30, 2013, SPS received $37.1 million and recognized a pre-tax gain of $13.6 million. The gain is reflected in the statement of income as a reduction to O&M expenses. Regulatory liabilities were recorded for jurisdictional gain sharing of $7.2 million.

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 — SPS has made commitments in connection with a portion of its projected capital expenditures.  SPS’ capital commitments primarily relate to transmission project plans.
	Southeast New Mexico Transmission Development — SPS is developing a transmission expansion plan for southeastern New Mexico. The SPP, with input from SPS, is conducting a High Priority Incremental Load Study to review oil and natural gas load additions in several areas, including southeastern New Mexico. A final report is expected by SPP in April 2014. SPS has started right-of-way work on four projects for which NTCs are anticipated from SPP in early 2014.
	Transmission NTC — SPS has accepted NTCs for several hundred miles of transmission line and related substation projects based on needs identified through SPP’s various planning processes, including those associated with economics, reliability, generator interconnection or the load addition processes. A major project committed to is the TUCO to Woodward District Extra High Voltage Interchange, a 345 KV transmission line. This line connects the TUCO substation near Lubbock, Texas with the OGE substation in Woodward, Okla. The PUCT approved SPS’ CCN to build the line in 2012. It is anticipated to be complete in 2014.
	Fuel Contracts — SPS has entered into various long-term commitments for the purchase and delivery of a significant portion of its current coal and natural gas requirements.  These contracts expire in various years between 2014 and 2033.  SPS is required to pay additional amounts depending on actual quantities shipped under these agreements.
	The estimated minimum purchases for SPS under these contracts as of Dec. 31, 2013, are as follows:
	(Millions of Dollars)		Coal		Natural gas			Natural gas
					supply			storage and
								transportation
	2014		$	273.8	$	20.6		$	23.7
	2015		241.5		—			22.1
	2016		143.8		—			22.1
	2017		36.7		—			21.3
	2018		—		—			15.9
	Thereafter		—		—			96.1
	Total		$	695.8	$	20.6		$	201.2
	Additional expenditures for fuel and natural gas storage and transportation will be required to meet expected future electric generation needs. SPS’ risk of loss, in the form of increased costs from market price changes in fuel, is mitigated through the cost-rate adjustment mechanisms, which provide for pass-through of most fuel, storage and transportation costs to customers.
	PPAs — SPS has entered into PPAs with other utilities and energy suppliers with expiration dates through 2024 for purchased power to meet system load and energy requirements and meet operating reserve obligations. In general, these contracts provide for energy payments, based on actual energy delivered and capacity payments. Capacity payments are typically contingent on the independent power producing entity meeting certain contract obligations, including plant availability requirements.  Certain contractual payments are adjusted based on market indices. The effects of price adjustments on our financial results are mitigated through purchased energy cost recovery mechanisms.
	Included in electric fuel and purchased power expenses for PPAs accounted for as executory contracts, were payments for capacity of $38.4 million, $36.2 million and $39.7 million in 2013, 2012 and 2011, respectively. At Dec. 31, 2013, the estimated future payments for capacity that SPS is obligated to purchase pursuant to these executory contracts, subject to availability, are as follows:
	(Millions of Dollars)
	2014		$	52.3
	2015		56.5
	2016		57
	2017		58.2
	2018		57.2
	Thereafter		72.2
	Total (a)		$	353.4
	(a)	Excludes contingent energy payments for renewable energy PPAs.
	Additional energy payments under these PPAs and PPAs accounted for as operating leases will be required to meet expected future electric demand.
	Leases — SPS leases a variety of equipment and facilities used in the normal course of business. These leases, primarily for office space, generating facilities, trucks, aircraft, cars and power-operated equipment, are accounted for as operating leases. Total expenses under operating lease obligations were approximately $64.2 million, $59.9 million and $58.8 million for 2013, 2012 and 2011, respectively. These expenses included capacity payments for PPAs accounted for as operating leases of $59.0 million, $56.0 million and $54.4 million in 2013, 2012 and 2011, respectively, recorded to electric fuel and purchased power expenses.
	Included in the future commitments under operating leases are estimated future capacity payments under PPAs that have been accounted for as operating leases in accordance with the applicable accounting guidance.  Future commitments under operating leases are:
			Operating		PPA			Total
								Operating
	(Millions of Dollars)		Leases		Operating Leases (a) (b)			Leases
	2014		$	3.1	$	58.3		$	61.4
	2015		3.2		49.9			53.1
	2016		3.2		49.9			53.1
	2017		2.3		49.9			52.2
	2018		1.9		49.9			51.8
	Thereafter		12.7		734.1			746.8
	(a)	Amounts do not include PPAs accounted for as executory contracts.
	(b)	PPA operating leases contractually expire through 2033.
	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.
	PPAs — Under certain PPAs, SPS purchases power from independent power producing entities for which SPS is required to reimburse natural gas fuel costs, or to participate in tolling arrangements under which SPS procures the natural gas required to produce the energy that it purchases. These specific PPAs create a variable interest in the associated independent power producing entity.
	SPS has determined that certain independent power producing entities are variable interest entities. SPS is not subject to risk of loss from the operations of these entities, and no significant financial support has been, or is in the future required to be provided other than contractual payments for energy and capacity set forth in the PPAs.
	SPS has evaluated each of these variable interest entities for possible consolidation, including review of qualitative factors such as the length and terms of the contract, control over O&M, control over dispatch of electricity, historical and estimated future fuel and electricity prices, and financing activities. SPS has concluded that these entities are not required to be consolidated in its financial statements because it does not have the power to direct the activities that most significantly impact the entities’ economic performance. SPS had approximately 827 MW of capacity under long-term PPAs as of Dec. 31, 2013 and 2012, with entities that have been determined to be variable interest entities. These agreements have expiration dates through the year 2033.
	Fuel Contracts — SPS purchases all of its coal requirements for its Harrington and Tolk electric generating stations from TUCO under contracts for those facilities that expire in 2016 and 2017, respectively. TUCO arranges for the purchase, receiving, transporting, unloading, handling, crushing, weighing, and delivery of coal to meet SPS’ requirements. TUCO is responsible for negotiating and administering contracts with coal suppliers, transporters and handlers.
	No significant financial support has been, or is in the future, required to be provided to TUCO by SPS, other than contractual payments for delivered coal. However, the fuel contracts create a variable interest in TUCO due to SPS’ reimbursement of certain fuel procurement costs. SPS has determined that TUCO is a variable interest entity. SPS has concluded that it is not the primary beneficiary of TUCO because SPS does not have the power to direct the activities that most significantly impact TUCO’s economic performance.
	Indemnification Agreements
	In connection with the sale of certain Texas electric transmission assets to Sharyland, SPS agreed to indemnify the purchaser for losses arising out of any breach of the representations, warranties and covenants under the related asset purchase agreement and for losses arising out of certain other matters, including pre-closing liabilities. SPS’ indemnification obligation is capped at $37.1 million, in the aggregate. The indemnification provisions for most representations and warranties expire in December 2014. The remaining representations and warranties, which relate to due organization and transaction authorization, survive indefinitely. SPS has recorded a $0.4 million liability related to this indemnity.
	Environmental Contingencies
	SPS has been or is currently involved with the cleanup of contamination from certain hazardous substances at several sites. In many situations, SPS believes it will recover some portion of these costs through insurance claims. Additionally, where applicable, SPS 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 SPS, which are normally recovered through the regulated rate process. To the extent any costs are not recovered through the options listed above, SPS 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. SPS may sometimes pay all or a portion of the cost to remediate sites where past activities of SPS or other parties have caused environmental contamination. Environmental contingencies could arise from various situations, including sites of former manufactured gas plants operated by SPS or other entities; and third-party sites, such as landfills, for which SPS is alleged to be a PRP that sent hazardous materials and wastes to that site.
	Environmental Requirements
	Water and waste
	Asbestos Removal — Some of SPS’ facilities contain asbestos. Most asbestos will remain undisturbed until the facilities that contain it are demolished or removed. SPS 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 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 SPS is uncertain at this time.
	Proposed Coal Ash Regulation — SPS’ 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. SPS’ 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. SPS 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 SPS’ 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 Texas. The CSAPR would have set more stringent requirements than the proposed Clean Air Transport Rule and would have required plants in Texas to reduce their SO2 and annual NOx emissions. 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, SPS 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. In the SPS region, installation of low-NOx combustion control technology was completed in 2012 on Tolk Unit 1. SPS plans to install the same combustion control technology on Tolk Unit 2 in the second quarter of 2014. These installations will reduce or eliminate SPS’ need to purchase NOx emission allowances. SPS had sufficient SO2 allowances to comply with the CAIR in 2013 and has sufficient allowances for 2014. At Dec. 31, 2013, the estimated annual CAIR NOx allowance cost for SPS 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. SPS expects to comply with the EGU MATS rule through a combination of mercury and other emission control projects. SPS believes EGU MATS costs will be recoverable through regulatory mechanisms and does not expect a material impact on results of operations, financial position or cash flows.
Regional Haze Rules — In 2005, the EPA amended the BART requirements of its regional haze rules, which require the installation and operation of emission controls for industrial facilities emitting air pollutants that reduce visibility in certain national parks and wilderness areas. In its first regional haze SIP, Texas identified the SPS facilities that will have to reduce SO2, NOx and PM emissions under BART and then set emissions limits for those facilities.
Harrington Units 1 and 2 are potentially subject to BART. Texas has developed a SIP that finds the CAIR equal to BART for EGUs. As a result, no additional controls beyond CAIR compliance would be required. In May 2012, the EPA deferred its review of the SIP in its final rule allowing states to find that CSAPR compliance meets BART requirements for EGUs. It is not yet known how the U.S. Supreme Court’s review of the CSAPR may impact the EPA’s approval of the SIP.
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 SPS 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 steam production, electric distribution and transmission, and general property.  The electric production obligations include asbestos, ash containment facilities, storage tanks and control panels.  The asbestos recognition associated with the steam production includes certain plants. This asbestos abatement removal obligation originated in 1973 with the CAA applied to the demolition of buildings or removal of equipment containing asbestos that can become airborne on removal.  The AROs also have been recorded for SPS steam production related to ash-containment facilities such as bottom ash ponds, evaporation ponds and solid waste landfills and the AROs origination dates on the ARO recognition for ash-containment facilities at steam plants were the in-service dates of the various facilities.
An ARO was recognized for the removal of electric transmission and distribution equipment at SPS, which consists of many small potential obligations associated with PCBs, mineral oil, storage tanks, treated poles, lithium batteries, mercury and street lighting lamps. The electric general AROs include small obligations related to storage tanks, radiation sources 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 SPS’ AROs is shown in the tables below for the years ended Dec. 31, 2013 and 2012:
(Thousands of Dollars)		Beginning Balance Jan. 1, 2013		Liabilities			Accretion		Revisions to Prior Estimates			Ending Balance Dec. 31, 2013
				Settled
Electric plant
Steam production asbestos		$	10,979	$	(118	)	$	747	$	—		$	11,608
Steam production ash containment		764		—			48		(3		)	809
Electric distribution		5,303		—			171		630			6,104
Other		561		—			42		251			854
Total liability		$	17,607	$	(118	)	$	1,008	$	878		$	19,375
(Thousands of Dollars)		Beginning Balance Jan. 1, 2012		Liabilities			Accretion		Revisions to Prior Estimates			Ending Balance Dec. 31, 2012
				Settled
Electric plant
Steam production asbestos		$	20,803	$	—		$	1,422	$	(11,246	)	$	10,979
Steam production ash containment		719		—			45		—			764
Electric distribution		5,202		—			188		(87		)	5,303
Other		542		—			20		(1		)	561
Total liability		$	27,266	$	—		$	1,675	$	(11,334	)	$	17,607
In 2013, SPS revised ash containment facilities, miscellaneous electric production, electric transmission and distribution and electric general AROs due to revised estimated cash flows. Additionally, in 2013, an ARO was settled for the asbestos abatement at the Riverview generating facility. In 2012, SPS revised asbestos and electric transmission and distribution AROs due to revised estimated cash flows.
Removal Costs — SPS records a regulatory liability for the 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 time periods over which the amounts were accrued and the changing of rates over time, SPS 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 $53 million and $67 million, respectively.
Legal Contingencies
SPS 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 SPS’ financial statements.  Unless otherwise required by GAAP, legal fees are expensed as incurred.
Employment, Tort and Commercial Litigation
Exelon Wind (formerly John Deere Wind) Complaint — Several lawsuits in Texas state and federal courts and regulatory proceedings have arisen out of a dispute concerning SPS’ payments for energy and capacity produced from the Exelon Wind subsidiaries’ projects. There are two main areas of dispute.  First, Exelon Wind claims that it established legally enforceable obligations (LEOs) for each of its 12 wind facilities in 2005 through 2008 that require SPS to buy power based on SPS’ forecasted avoided cost as determined in 2005 through 2008.  Although SPS has refused to accept Exelon Wind’s LEOs, SPS accepts that it must take energy from Exelon Wind under SPS’ PUCT-approved QF Tariff.  Second, Exelon Wind has raised various challenges to SPS’ PUCT-approved QF Tariff, which became effective in August 2010. The state and federal lawsuits and regulatory proceedings are in various stages of litigation, including a pending appeal by SPS in the Fifth Circuit Court of Appeals. SPS believes the likelihood of loss in these lawsuits and proceedings is remote based primarily on existing case law and while it is not possible to estimate the amount or range of reasonably possible loss in the event of an adverse outcome, SPS believes such loss would not be material based upon its belief that it would be permitted to recover such costs, if needed, through its various fuel clause mechanisms. No accrual has been recorded for this matter.
Other Contingencies
See Note 10 for further discussion.

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
	SPS’ 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 rates.  If changes in the utility industry or the business of SPS no longer allow for the application of regulatory accounting guidance under GAAP, SPS 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 balance sheets of SPS at Dec. 31, 2013 and 2012 are:
	(Thousands of Dollars)		See	Remaining	Dec. 31, 2013				Dec. 31, 2012
			Note(s)	Amortization Period
	Regulatory Assets				Current		Noncurrent		Current		Noncurrent
	Pension and retiree medical obligations (a)		7	Various	$	17,382	$	200,158	$	15,038	$	238,398
	Recoverable deferred taxes on AFUDC recorded in plant		1	Plant lives	—		31,362		—		27,591
	Net AROs (b)		11	Plant lives	—		21,382		—		21,714
	Conservation programs (c)		1	One to six years	1,951		7,753		1,735		9,095
	Renewable resources and environmental initiatives		11	One to four years	3,428		17,671		4,094		15,101
	Losses on reacquired debt		4	Term of related debt	1,225		3,697		1,225		4,922
	Deferred income tax adjustment		1, 6	Typically plant lives	—		3,375		—		4,859
	Recoverable electric energy costs		1	Less than one year	491		—		873		—
	Other			Various	3,118		5,017		1,055		2,401
	Total regulatory assets				$	27,595	$	290,415	$	24,020	$	324,081
	(a)	Includes the non-qualified pension plan.
	(b)	Includes amounts recorded for future recovery of AROs.
	(c)	Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions.
	The components of regulatory liabilities shown on the balance sheets of SPS at Dec. Dec. 31, 2013 and 2012 are:
	(Thousands of Dollars)		See	Remaining	Dec. 31, 2013				Dec. 31, 2012
			Note(s)	Amortization Period
	Regulatory Liabilities				Current		Noncurrent		Current		Noncurrent
	Plant removal costs		11	Plant lives	$	—	$	53,006	$	—	$	66,575
	Deferred electric energy costs		1	Less than one year	55,395		—		61,874		—
	Contract valuation adjustments (a)		1, 9	Term of related contract	14,243		6,849		4,292		11,159
	Gain from asset sales		10	Various	11,172		4,201		4,903		8,272
	Conservation programs (b)		1	Less than one year	1,465		—		1,875		—
	Other			Various	1,484		17,448		2,947		5,809
	Total regulatory liabilities				$	83,759	$	81,504	$	75,891	$	91,815
	(a)	Includes the fair value of certain long-term PPAs used to meet energy capacity requirements.
	(b)	Includes costs for conservation programs as well as incentives allowed in certain jurisdictions.
	At Dec. 31, 2013 and 2012, approximately $30 million and $25 million of SPS’ regulatory assets represented past expenditures not currently earning a return, respectively.  This amount primarily includes certain expenditures associated with renewable resources and environmental initiatives.

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		$	(1,332	)
	Losses reclassified from net accumulated other comprehensive loss		171
	Net current period OCI		171
	Accumulated other comprehensive loss at Dec. 31		$	(1,161	)
	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		$	268		(a)
	Total, pre-tax		268
	Tax benefit		(97		)
	Total amounts reclassified, net of tax		$	171
	(a)	Included in interest charges.

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 SPS. The services are provided and billed to each subsidiary in accordance with service agreements executed by each subsidiary. SPS uses the service provided by Xcel Energy Services Inc. whenever possible. Costs are charged directly to the subsidiary and are allocated if they cannot be directly assigned.
	Xcel Energy Inc., NSP-Minnesota, PSCo and SPS have established a utility money pool arrangement with the utility subsidiaries. See Note 4 for further discussion of this borrowing arrangement.
	The table below contains significant affiliate transactions among the companies and related parties for the years ended Dec. 31:
	(Thousands of Dollars)	2013		2012		2011
	Operating revenues:
	Electric	$	1,331	$	6,539	$	7,187
	Operating expenses:
	Purchased power	8,136		9,271		10,896
	Other operating expenses — paid to Xcel Energy Services Inc.	127,669		117,277		118,370
	Interest expense	178		76		83
	Interest income	—		10		1
	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	$	3,462	$	—	$	3,820	$	—
	NSP-Wisconsin	—		26		4		—
	PSCo	—		1,056		—		69
	Other subsidiaries of Xcel Energy Inc.	12,378		14,305		967		12,294
		$	15,840	$	15,387	$	4,791	$	12,363

Summarized_Quarterly_Financial

Summarized Quarterly Financial Data (Unaudited)	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	$	374,257	$	461,831	$	481,407	$	389,592
	Operating income	33,059		58,469		74,653		43,836
	Net income	12,584		28,206		35,037		19,350
		Quarter Ended
	(Thousands of Dollars)	March 31, 2012		June 30, 2012		Sept. 30, 2012		Dec. 31, 2012
	Operating revenues	$	340,488	$	380,201	$	471,889	$	347,477
	Operating income	31,845		61,891		107,509		24,510
	Net income	11,360		30,294		58,247		6,468

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	'
	SOUTHWESTERN PUBLIC SERVICE CO.
	VALUATION AND QUALIFYING ACCOUNTS
	YEARS ENDED DEC. 31, 2013, 2012 AND 2011
	(amounts in thousands)
					Additions
			Balance at		Charged to		Charged to		Deductions		Balance at
			Jan. 1		Costs and		Other		from		Dec. 31
					Expenses		Accounts(a)		Reserves (b)
	Allowance for bad debts:
	2013		$	4,722	$	3,437	$	1,076	$	3,760	$	5,475
	2012		5,380		2,915		1,202		4,775		4,722
	2011		5,095		3,655		1,139		4,509		5,380
	(a)	Recovery of amounts previously written off.
	(b)	Principally bad debts written off.

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 — SPS is principally engaged in the regulated generation, purchase, transmission, distribution and sale of electricity. SPS’ financial statements and disclosures are presented in accordance with GAAP.  All of SPS’ 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.
Variable Interest Entities	'
	Variable Interest Entities — SPS evaluates its arrangements and contracts with other entities, including but not limited to, PPAs and fuel contracts to determine if the other party is a variable interest entity, if SPS has a variable interest and if SPS is the primary beneficiary. SPS 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 SPS 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, SPS 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 — SPS 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, SPS 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 SPS’ 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.  SPS presents its revenues net of any excise or other fiduciary-type taxes or fees.
	SPS participates in SPP.  The revenues and charges from SPP related to serving retail and wholesale electric customers comprising the native load of SPS are recorded on a net basis within cost of sales.  Revenues and charges for short-term wholesale sales of excess energy transacted through SPP are recorded on a gross basis in electric revenues and cost of sales.
	SPS has various rate-adjustment mechanisms in place that provide for the recovery of electric fuel costs and purchased energy costs. These cost-adjustment tariffs may increase or decrease the level of revenue collected from customers and are revised periodically for differences between the total amount collected under the clauses and the costs incurred.  When applicable, under governing regulatory commission rate orders, fuel cost over-recoveries (the excess of fuel revenue billed to customers over fuel costs incurred) are deferred as regulatory liabilities and under-recoveries (the excess of fuel costs incurred over fuel revenues billed to customers) are deferred as regulatory assets.
Conservation Programs	'
	Conservation Programs — SPS has implemented programs in its jurisdictions to assist customers in conserving energy and reducing peak demand on the electric system.  These programs include commercial process efficiency and lighting updates, as well as residential rebates for participation in air conditioner interruption and energy-efficient appliances.
	The costs incurred for some DSM programs are deferred as permitted by the applicable regulatory jurisdiction. For those programs, costs are deferred if it is probable future revenue will be provided to permit recovery of the incurred cost. For incentive programs designed to allow adjustments of future rates for recovery of lost margins and/or conservation performance incentives, recorded revenues are limited to those amounts expected to be collected within 24 months following the end of the annual period in which they are earned.  SPS recovers approved conservation program costs in base rate revenue or through a rider.
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.
	SPS 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 2.6, 2.7 and 2.7 percent for the years ended Dec. 31, 2013, 2012 and 2011, respectively.
Leases	'
	Leases — SPS evaluates a variety of contracts for lease classification at inception, including PPAs and 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 SPS’ rate base for establishing utility service rates.
Asset Retirement Obligations	'
	AROs — SPS 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.
	SPS 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.
Income Taxes	'
	Income Taxes — SPS 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.  SPS defers income taxes for all temporary differences between pretax financial and taxable income, and between the book and tax bases of assets and liabilities. SPS 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 rate making 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.
	SPS 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. SPS recognizes a tax position in its 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.
	SPS reports interest and penalties related to income taxes within the other income and interest charges sections in the statements of income.
	Xcel Energy Inc. and its subsidiaries, including SPS, 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 — SPS uses derivative instruments in connection with its utility commodity price, interest rate, short-term wholesale and commodity trading 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 balance sheets at fair value as derivative instruments.  This includes certain instruments used to mitigate market risk for the utility operations including transmission in organized markets and all instruments related to the commodity trading 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 expected recovery of derivative instrument settlements through fuel and purchased energy cost recovery mechanisms.
	Gains or losses on commodity trading transactions are recorded as a component of electric operating revenues.  Interest rate hedging transactions are recorded as a component of interest expense. For further information on derivatives entered to mitigate market risk associated with transmission in organized markets, 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 — SPS 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.
	SPS 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.  None of the contracts entered into within the commodity trading operations qualify for a normal purchases and normal sales designation.
	See Note 9 for further discussion of SPS’ risk management and derivative activities.
Commodity Trading Operations	'
	Commodity Trading Operations — All applicable gains and losses related to commodity trading activities, whether or not settled physically, are shown on a net basis in electric operating revenues in the statements of income.
	Pursuant to the JOA approved by the FERC, some of the commodity trading margins from SPS are apportioned to NSP-Minnesota and PSCo. Commodity trading activities are not associated with energy produced from SPS’ generation assets or energy and capacity purchased to serve native load.  Commodity trading contracts are recorded at fair market value and commodity trading results include the impact of all margin-sharing mechanisms.  See Note 9 for further discussion.
Fair Value Measurements	'
	Fair Value Measurements — SPS presents cash equivalents, interest rate derivatives and commodity derivatives at estimated fair values in its 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, SPS 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 — SPS 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. SPS 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.  SPS 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.  As a result of certain state regulatory orders, SPS reduces recoverable fuel costs for the cost of certain RECs and records that cost as a regulatory asset when the amount is recoverable in future rates.  Sales of RECs that are purchased or acquired in the course of generation are recorded in electric utility operating revenues on a gross basis.  The cost of these RECs, related transaction costs, and amounts credited to customers under margin-sharing mechanisms are recorded in electric fuel and purchased power expense.
Emission Allowances	'
	Emission Allowances — Emission allowances, including the annual SO2 and NOx emission allowance entitlement received from the EPA, are recorded at cost plus associated broker commission fees.  SPS 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 statements of cash flows.
Environmental Costs	'
	Environmental Costs — Environmental costs are recorded when it is probable SPS 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 SPS’ 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 — SPS 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 — SPS 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 SPS is released from risk under the guarantee.  See Note 11 for specific details of issued guarantees.
Segment Information	'
	Segment Information - SPS has only one reportable segment.  SPS is a wholly owned subsidiary of Xcel Energy Inc. and operates in the regulated electric utility industry providing wholesale and retail electric service in the states of Texas and New Mexico.  Operating results from the regulated electric utility segment serve as the primary basis for the chief operating decision maker to evaluate the performance of SPS.
Subsequent Events	'
	Subsequent Events — Management has evaluated the impact of events occurring after Dec. 31, 2013 up to the date of issuance of these 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
	Accounts receivable	$	76,426		$	66,789
	Less allowance for bad debts	(5,475		)	(4,722		)
		$	70,951		$	62,067
Inventories	'
	(Thousands of Dollars)	Dec. 31, 2013			Dec. 31, 2012
	Inventories
	Materials and supplies	$	21,600		$	18,129
	Fuel	15,538			13,208
		$	37,138		$	31,337
Property, Plant and Equipment, Net	'
	(Thousands of Dollars)	Dec. 31, 2013			Dec. 31, 2012
	Property, plant and equipment, net
	Electric plant	$	4,714,398		$	4,379,208
	Construction work in progress	388,323			237,136
	Total property, plant and equipment	5,102,721			4,616,344
	Less accumulated depreciation	(1,818,691		)	(1,754,588		)
		$	3,284,030		$	2,861,756

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, SPS had the following committed credit facility available (in millions):
	Credit Facility (a)				Drawn (b)				Available
	$	300			$	109.5			$	190.5
	(a)	Credit facility expires in July 2017.
	(b)	Includes outstanding commercial paper and letters of credit.
Money Pool	'
Borrowings and Other Financing Instruments [Abstract]	'
Short-Term Borrowings	'
	Money Pool — Xcel Energy Inc. and its utility subsidiaries have established a money pool arrangement that allows for short-term investments in and borrowings between the utility subsidiaries. Xcel Energy Inc. may make investments in the utility subsidiaries at market-based interest rates; however, the money pool arrangement does not allow the utility subsidiaries to make investments in Xcel Energy Inc. Money pool borrowings for SPS were as follows:
	(Amounts in Millions, Except Interest Rates)		Three Months Ended Dec. 31, 2013
	Borrowing limit		$	100
	Amount outstanding at period end		38
	Average amount outstanding		65
	Maximum amount outstanding		100
	Weighted average interest rate, computed on a daily basis		0.18		%
	Weighted average interest rate at period end		0.25
	(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		$	100			$	100			$	100
	Amount outstanding at period end		38				—				5
	Average amount outstanding		46				10				12
	Maximum amount outstanding		100				63				71
	Weighted average interest rate, computed on a daily basis		0.15		%		0.33		%		0.35		%
	Weighted average interest rate at end of period		0.25				N/A				0.35
Commercial Paper	'
Borrowings and Other Financing Instruments [Abstract]	'
Short-Term Borrowings	'
	Commercial Paper — SPS meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under its credit facility. Commercial paper outstanding for SPS was as follows:
	(Amounts in Millions, Except Interest Rates)		Three Months Ended Dec. 31, 2013
	Borrowing limit		$	300
	Amount outstanding at period end		84
	Average amount outstanding		60
	Maximum amount outstanding		121
	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		$	300			$	300			$	300
	Amount outstanding at period end		84				9				—
	Average amount outstanding		32				18				54
	Maximum amount outstanding		140				106				161
	Weighted average interest rate, computed on a daily basis		0.3		%		0.39		%		0.37		%
	Weighted average interest rate at end of period		0.27				0.36				N/A

Preferred_Stock_Tables

Preferred Stock (Tables)	12 Months Ended
	Dec. 31, 2013
Equity [Abstract]	'
Preferred Stock	'
	SPS has authorized the issuance of preferred stock.
	Preferred	Par Value		Preferred
	Shares			Shares
	Authorized			Outstanding
	10,000,000	$	1	None

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	$	1.2			$	0.2
	Unrecognized tax benefit — Temporary tax positions	2.9				3.7
	Total unrecognized tax benefit	$	4.1			$	3.9
	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	$	3.9			$	4.8			$	4.3
	Additions based on tax positions related to the current year	1.6				1.1				1.5
	Reductions based on tax positions related to the current year	—				(1.6		)		(0.2		)
	Additions for tax positions of prior years	3.1				0.8				2.5
	Reductions for tax positions of prior years	(0.3		)		(1.2		)		(0.3		)
	Settlements with taxing authorities	(4.2		)		—				(3.0		)
	Balance at Dec. 31	$	4.1			$	3.9			$	4.8
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	$	(2.4	)		$	(2.0	)
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	168.7			158
	Federal tax credit carryforwards	1.7			1.3
	State NOL carryforwards	23.6			21
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	2			2.2			2.9
	Change in unrecognized tax benefits	0.7			—			—
	Regulatory differences — utility plant items	(1.1	)		(0.4	)		(0.1	)
	Tax credits recognized	(0.4	)		(0.2	)		(0.3	)
	Other, net	(0.1	)		0.3			0.5
	Effective income tax rate	36.1	%		36.9	%		38	%
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)	$	14,947			$	6,549			$	(1,993	)
	Current state tax expense	2,943				2,712				3,287
	Current change in unrecognized tax benefit	(263		)		(824		)		(1,394		)
	Deferred federal tax expense	33,489				50,189				50,903
	Deferred state tax expense	1,754				3,069				3,240
	Deferred change in unrecognized tax expense	1,232				861				1,365
	Deferred investment tax credits	(341		)		(327		)		(275		)
	Total income tax expense	$	53,761			$	62,229			$	55,133
	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	$	38,333			$	55,749			$	56,181
	Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities	(1,761		)		(1,533		)		(575		)
	Tax expense allocated to other comprehensive income	(97		)		(97		)		(98		)
	Deferred tax expense	$	36,475			$	54,119			$	55,508
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:
	Differences between book and tax bases of property	$	705,416			$	654,259
	Employee benefits	52,081				51,394
	Other	30,066				24,034
	Total deferred tax liabilities	$	787,563			$	729,687
	Deferred tax assets:
	NOL carryforward	$	61,330			$	59,562
	Rate refund	17,192				2,911
	Unbilled revenue - fuel costs	13,316				10,555
	Regulatory liabilities	9,724				6,176
	Deferred fuel costs	6,877				11,952
	Other	6,708				4,448
	Total deferred tax assets	$	115,147			$	95,604
	Net deferred tax liability	$	672,416			$	634,083

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	'
	Projected Benefit Payments — The following table lists SPS’ projected benefit payments for the pension and postretirement benefit plans:
	(Thousands of Dollars)		Projected				Gross Projected				Expected			Net Projected
			Pension Benefit				Postretirement				Medicare Part D			Postretirement
			Payments				Health Care				Subsidies			Health Care
							Benefit Payments							Benefit Payments
	2014		$	26,265			$	3,285			$	33		$	3,252
	2015		27,361				3,450				36			3,414
	2016		27,565				3,547				50			3,497
	2017		28,738				3,691				52			3,639
	2018		29,703				3,582				55			3,527
	2019-2023		153,507				17,912				186			17,726
Pension Plans	'
Benefit Plans and Other Postretirement Benefits [Abstract]	'
Target Asset Allocations and Plan Assets Measured at Fair Value	'
	The following tables present, for each of the fair value hierarchy levels, SPS’ 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		$	17,354			$	—			$	—		$	17,354
	Derivatives		—				4,200				—			4,200
	Government securities		—				26,649				—			26,649
	Corporate bonds		—				79,635				—			79,635
	Asset-backed securities		—				889				—			889
	Mortgage-backed securities		—				1,939				—			1,939
	Common stock		12,813				—				—			12,813
	Private equity investments		—				—				18,222			18,222
	Commingled funds		—				223,322				—			223,322
	Real estate		—				—				5,755			5,755
	Securities lending collateral obligation and other		—				2,615				—			2,615
	Total		$	30,167			$	339,249			$	23,977		$	393,393
			Dec. 31, 2012
	(Thousands of Dollars)		Level 1				Level 2				Level 3			Total
	Cash equivalents		$	26,765			$	—			$	—		$	26,765
	Derivatives		—				1,388				—			1,388
	Government securities		—				33,676				—			33,676
	Corporate bonds		—				95,726				—			95,726
	Asset-backed securities		—				—				1,755			1,755
	Mortgage-backed securities		—				—				4,331			4,331
	Common stock		7,762				—				—			7,762
	Private equity investments		—				—				17,049			17,049
	Commingled funds		—				183,957				—			183,957
	Real estate		—				—				6,969			6,969
	Securities lending collateral obligation and other		—				(3,240		)		—			(3,240		)
	Total		$	34,527			$	311,507			$	30,104		$	376,138
	The following table presents the target pension asset allocations for SPS:
			2013			2012
	Domestic and international equity securities		29	%		21	%
	Long-duration fixed income and interest rate swap securities		36			50
	Short-to-intermediate term fixed income securities		14			8
	Alternative investments		19			19
	Cash		2			2
	Total		100	%		100	%
Changes in Level 3 Plan Assets	'
	The following tables present the changes in SPS’ Level 3 pension plan assets for the years ended Dec. 31, 2013, 2012 and 2011:
	(Thousands of Dollars)		Jan. 1, 2013				Net Realized Gains (Losses)				Net Unrealized Gains (Losses)			Purchases,			Transfers Out of Level 3 (a)			Dec. 31, 2013
														Issuances and Settlements, Net
	Asset-backed securities		$	1,755			$	—			$	—		$	—		$	(1,755	)	$	—
	Mortgage-backed securities		4,331				—				—			—			(4,331		)	—
	Private equity investments		17,049				2,630				(1,055		)	(402		)	—			18,222
	Real estate		6,969				(322		)		1,475			1,128			(3,495		)	5,755
	Total		$	30,104			$	2,308			$	420		$	726		$	(9,581	)	$	23,977
	(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 Gains (Losses)				Net Unrealized Gains (Losses)			Purchases,			Transfers Out of Level 3			Dec. 31, 2012
														Issuances and Settlements, Net
	Asset-backed securities		$	4,018			$	531			$	(741	)	$	(2,053	)	$	—		$	1,755
	Mortgage-backed securities		7,907				245				(265		)	(3,556		)	—			4,331
	Private equity investments		16,159				1,886				(2,296		)	1,300			—			17,049
	Real estate		3,586				2				551			2,830			—			6,969
	Total		$	31,670			$	2,664			$	(2,751	)	$	(1,479	)	$	—		$	30,104
	(Thousands of Dollars)		Jan. 1, 2011				Net Realized Gains (Losses)				Net Unrealized Gains (Losses)			Purchases,			Transfers Out of Level 3			Dec. 31, 2011
														Issuances and Settlements, Net
	Asset-backed securities		$	3,450			$	328			$	(355	)	$	595		$	—		$	4,018
	Mortgage-backed securities		11,060				170				(865		)	(2,458		)	—			7,907
	Private equity investments		11,464				401				1,300			2,994			—			16,159
	Real estate		10,132				(61		)		3,131			(9,616		)	—			3,586
	Total		$	36,106			$	838			$	3,211		$	(8,485	)	$	—		$	31,670
Change in Projected Benefit Obligation	'
	Benefit Obligations — A comparison of the actuarially computed pension benefit obligation and plan assets for SPS is presented in the following table:
	(Thousands of Dollars)		2013				2012
	Accumulated Benefit Obligation at Dec. 31		$	402,509			$	416,808
	Change in Projected Benefit Obligation:
	Obligation at Jan. 1		$	454,184			$	403,367
	Service cost		9,615				8,520
	Interest cost		17,908				19,697
	Plan amendments		—				98
	Actuarial (gain) loss		(27,185		)		45,881
	Transfer from other plan		3,625				—
	Benefit payments		(23,840		)		(23,379		)
	Obligation at Dec. 31		$	434,307			$	454,184
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		$	376,138			$	350,054
	Actual return on plan assets		15,455				36,403
	Employer contributions		22,015				13,060
	Transfer from other plan		3,625				—
	Benefit payments		(23,840		)		(23,379		)
	Fair value of plan assets at Dec. 31		$	393,393			$	376,138
Funded Status of Plans	'
	(Thousands of Dollars)		2013				2012
	Funded Status of Plans at Dec. 31:
	Funded status (a)		$	(40,914	)		$	(78,046	)
	(a)	Amounts are recognized in noncurrent liabilities on SPS’ 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		$	208,594			$	244,412
	Prior service cost		93				963
	Total		$	208,687			$	245,375
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		$	15,843			$	14,877
	Noncurrent regulatory assets		192,844				230,498
	Total		$	208,687			$	245,375
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		6.49			6.68			6.8
	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 SPS’ net periodic pension cost were:
	(Thousands of Dollars)		2013				2012				2011
	Service cost		$	9,615			$	8,520			$	7,690
	Interest cost		17,908				19,697				20,036
	Expected return on plan assets		(23,970		)		(24,928		)		(26,316		)
	Amortization of prior service cost		870				1,438				1,505
	Amortization of net loss		17,148				12,897				9,046
	Net periodic pension cost		$	21,571			$	17,624			$	11,961
	Costs not recognized due to effects of regulation		(1,269		)		(4,300		)		(2,300		)
	Net benefit cost recognized for financial reporting		$	20,302			$	13,324			$	9,661
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, SPS’ 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		$	1,941			$	—			$	—		$	1,941
	Derivatives		—				(38		)		—			(38		)
	Government securities		—				5,549				—			5,549
	Insurance contracts		—				5,016				—			5,016
	Corporate bonds		—				4,926				—			4,926
	Asset-backed securities		—				319				—			319
	Mortgage-backed securities		—				2,303				—			2,303
	Commingled funds		—				28,331				—			28,331
	Other		—				(1,609		)		—			(1,609		)
	Total		$	1,941			$	44,797			$	—		$	46,738
			Dec. 31, 2012
	(Thousands of Dollars)		Level 1				Level 2				Level 3			Total
	Cash equivalents		$	8,774			$	—			$	—		$	8,774
	Government securities		—				7,061				—			7,061
	Insurance contracts		—				4,807				—			4,807
	Corporate bonds		—				4,211				—			4,211
	Asset-backed securities		—				—				73			73
	Mortgage-backed securities		—				—				3,841			3,841
	Commingled funds		—				21,958				—			21,958
	Other		—				(4,503		)		—			(4,503		)
	Total		$	8,774			$	33,534			$	3,914		$	46,222
Changes in Level 3 Plan Assets	'
	The following tables present the changes in SPS’ Level 3 postretirement benefit plan assets for the years ended Dec. 31, 2013, 2012 and 2011:
	(Thousands of Dollars)		Jan. 1, 2013				Net Realized Gains (Losses)				Net Unrealized Gains (Losses)			Purchases,			Transfers Out of Level 3 (a)			Dec. 31, 2013
														Issuances and Settlements, Net
	Asset-backed securities		$	73			$	—			$	—		$	—		$	(73	)	$	—
	Mortgage-backed securities		3,841				—				—			—			(3,841		)	—
	Total		$	3,914			$	—			$	—		$	—		$	(3,914	)	$	—
	(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 Gains (Losses)				Net Unrealized Gains (Losses)			Purchases,			Transfers Out of Level 3			Dec. 31, 2012
														Issuances and Settlements, Net
	Asset-backed securities		$	730			$	(32	)		$	179		$	(804	)	$	—		$	73
	Mortgage-backed securities		2,535				(70		)		377			999			—			3,841
	Total		$	3,265			$	(102	)		$	556		$	195		$	—		$	3,914
	(Thousands of Dollars)		Jan. 1, 2011				Net Realized Gains (Losses)				Net Unrealized Gains (Losses)			Purchases,			Transfers Out of Level 3			Dec. 31, 2011
														Issuances and Settlements, Net
	Asset-backed securities		$	245			$	(2	)		$	(101	)	$	588		$	—		$	730
	Mortgage-backed securities		1,820				(157		)		194			678			—			2,535
	Total		$	2,065			$	(159	)		$	93		$	1,266		$	—		$	3,265
Change in Projected Benefit Obligation	'
	Benefit Obligations — A comparison of the actuarially computed benefit obligation and plan assets for SPS is presented in the following table:
	(Thousands of Dollars)		2013				2012
	Change in Projected Benefit Obligation:
	Obligation at Jan. 1		$	59,260			$	55,165
	Service cost		1,368				1,259
	Interest cost		2,352				2,831
	Medicare subsidy reimbursements		63				404
	Plan amendments		—				(4,334		)
	Plan participants’ contributions		698				2,004
	Actuarial (gain) loss		(5,215		)		7,120
	Benefit payments		(3,544		)		(5,189		)
	Obligation at Dec. 31		$	54,982			$	59,260
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		$	46,222			$	39,679
	Actual return on plan assets		3,228				5,375
	Plan participants’ contributions		698				2,004
	Employer contributions		134				4,353
	Benefit payments		(3,544		)		(5,189		)
	Fair value of plan assets at Dec. 31		$	46,738			$	46,222
Funded Status of Plans	'
	(Thousands of Dollars)		2013				2012
	Funded Status of Plans at Dec. 31:
	Funded status (a)		$	(8,244	)		$	(13,038	)
	(a)	Amounts are recognized in noncurrent liabilities on SPS’ balance sheet.
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 Credit:
	Net gain		$	(5,344	)		$	(90	)
	Prior service credit		(3,833		)		(4,317		)
	Transition obligations		—				—
	Total		$	(9,177	)		$	(4,407	)
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 liabilities		$	(319	)		$	(954	)
	Noncurrent regulatory liabilities		(8,858		)		(3,453		)
	Total		$	(9,177	)		$	(4,407	)
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 SPS’ net periodic postretirement benefit cost were:
	(Thousands of Dollars)		2013				2012				2011
	Service cost		$	1,368			$	1,259			$	1,092
	Interest cost		2,352				2,831				2,722
	Expected return on plan assets		(3,183		)		(2,701		)		(3,006		)
	Amortization of transition obligation		—				1,545				1,669
	Amortization of prior service credit		(484		)		(148		)		(51		)
	Amortization of net (gain) loss		(6		)		1,256				855
	Net periodic postretirement benefit cost		$	47			$	4,042			$	3,281
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 SPS:
			One-Percentage Point
	(Thousands of Dollars)		Increase				Decrease
	APBO		$	5,684			$	(4,763	)
	Service and interest components		368				(290		)

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	$	663		$	379		$	506
	Other nonoperating income	9			36			11
	Insurance policy expense	(532		)	(369		)	(111		)
	Other income, net	$	140		$	46		$	406

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 FTRs	'
	The following table details the gross notional amounts of commodity FTRs at Dec. 31, 2013:
	(Amounts in Thousands) (a)(b)		Dec. 31, 2013
	MWh of electricity		5,989
	(a)	Amounts are not reflective of net positions in the underlying commodities.
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 SPS’ accumulated other comprehensive loss, included in the statements of common stockholder’s equity and in the 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		$	(1,332	)	$	(1,504	)	$	(1,675	)
	After-tax net realized losses on derivative transactions reclassified into earnings		171			172			171
	Accumulated other comprehensive loss related to cash flow hedges at Dec. 31		$	(1,161	)	$	(1,332	)	$	(1,504	)
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, SPS’ 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 Total		Counterparty Netting (b)			Total
	Current derivative assets
	Other derivative instruments:
	Electric commodity		$	—		$	—		$	16,420		$	16,420	$	(6,487	)	$	9,933
	Total current derivative assets		$	—		$	—		$	16,420		$	16,420	$	(6,487	)	9,933
	PPAs (a)																7,893
	Current derivative instruments																$	17,826
	Noncurrent derivative assets
	PPAs (a)																$	41,056
	Noncurrent derivative instruments																$	41,056
	Current derivative liabilities
	Other derivative instruments:
	Electric commodity		$	—		$	—		$	6,487		$	6,487	$	(6,487	)	$	—
	Total current derivative liabilities		$	—		$	—		$	6,487		$	6,487	$	(6,487	)	—
	PPAs (a)																3,583
	Current derivative instruments																$	3,583
	Noncurrent derivative liabilities
	PPAs (a)																$	34,207
	Noncurrent derivative instruments																$	34,207
	(a)	In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, SPS began recording several long-term PPAs at fair value due to accounting requirements related to underlying price adjustments.  As these purchases are recovered through normal regulatory recovery mechanisms in the respective jurisdictions, the changes in fair value for these contracts were offset by regulatory assets and liabilities.  During 2006, SPS qualified these contracts under the normal purchase exception.  Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.
	(b)	SPS 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.  At Dec. 31, 2013, derivative assets and liabilities include no obligations to return cash collateral or rights to reclaim cash collateral. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.
Changes in Level 3 Commodity Derivatives	'
	The following table presents the changes in Level 3 commodity derivatives for the year ended Dec. 31, 2013:
	(Thousands of Dollars)		2013
	Balance at Jan. 1		$	—
	Purchases		9,933
	Balance at Dec. 31		$	9,933
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			Fair Value			Carrying			Fair Value
			Amount						Amount
	Long-term debt, including current portion		$	1,199,865		$	1,307,035		$	1,103,684		$	1,327,538

Rate_Matters_Rate_Matters_Tabl

Rate Matters Rate Matters (Tables)	12 Months Ended
	Dec. 31, 2013
Public Utilities, General Disclosures [Abstract]	'
SPS' Texas 2014 Electric Rate Case	'
	Texas 2014 Electric Rate Case — On Jan. 7, 2014, SPS filed a retail electric rate case in Texas with each of its Texas municipalities and the PUCT for a net increase in annual revenue of approximately $52.7 million, or 5.8 percent. The net increase reflects a base rate increase, revenue credits transferred from base rates to rate riders or the fuel clause, and resetting the TCRF to zero when the final base rates become effective, as shown in the following table:
	(Millions of Dollars)		SPS Request
	Base rate increase		$	81.5
	Resetting TCRF		(12.9		)
	Credit to customers for gain on sale to Lubbock moved to a rider		(4.9		)
	Net increase in base revenue		63.7
	Fuel clause offsets		(11.0		)
	Retail customer net bill impact		$	52.7
New Mexico Public Regulation Commission (NMPRC) and New Mexico Attorney General (NMAG) recommendations to SPS' New Mexico 2014 Electric Rate Case	'
	The following table summarizes certain parties’ recommendations from SPS’ revised request:
	(Millions of Dollars)		Staff			NMAG
			Testimony			Testimony
			Aug-13			Aug-13
	SPS revised request		$	43.3		$	43.3
	Rate rider for renewable energy costs (a)		(14.5		)	(8.5		)
	Present revenues (sales growth and weather)		(4.4		)	(6.4		)
	ROE (9.8 percent and 8.63 percent, respectively)		(3.2		)	(8.1		)
	Capital structure		(1.5		)	(1.1		)
	Employee benefits		(2.8		)	(1.8		)
	Reduced recovery for payroll expense		(0.1		)	(0.1		)
	Gain on sale of transmission assets		—			(1.7		)
	Fuel clause revenue		6			—
	Other, net		(5.0		)	(6.6		)
	Recommended rate increase		$	17.8		$	9
	Means of recovery:
	Base revenue		$	8.8		$	(6.0	)
	Rider revenue		7.3			13.3
	Fuel cost adjustment revenue		1.7			1.7
			$	17.8		$	9
	(a)	Adjustments represent recommended deferrals, extended amortizations and moving costs from rider to fuel in base rates.

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 SPS under these contracts as of Dec. 31, 2013, are as follows:
	(Millions of Dollars)		Coal		Natural gas			Natural gas
					supply			storage and
								transportation
	2014		$	273.8	$	20.6		$	23.7
	2015		241.5		—			22.1
	2016		143.8		—			22.1
	2017		36.7		—			21.3
	2018		—		—			15.9
	Thereafter		—		—			96.1
	Total		$	695.8	$	20.6		$	201.2
Estimated Future Payments for Capacity Pursuant to Purchased Power Agreements	'
	At Dec. 31, 2013, the estimated future payments for capacity that SPS is obligated to purchase pursuant to these executory contracts, subject to availability, are as follows:
	(Millions of Dollars)
	2014		$	52.3
	2015		56.5
	2016		57
	2017		58.2
	2018		57.2
	Thereafter		72.2
	Total (a)		$	353.4
	(a)	Excludes contingent energy payments for renewable energy PPAs.
Future Commitments Under Operating Leases	'
	Included in the future commitments under operating leases are estimated future capacity payments under PPAs that have been accounted for as operating leases in accordance with the applicable accounting guidance.  Future commitments under operating leases are:
			Operating		PPA			Total
								Operating
	(Millions of Dollars)		Leases		Operating Leases (a) (b)			Leases
	2014		$	3.1	$	58.3		$	61.4
	2015		3.2		49.9			53.1
	2016		3.2		49.9			53.1
	2017		2.3		49.9			52.2
	2018		1.9		49.9			51.8
	Thereafter		12.7		734.1			746.8
	(a)	Amounts do not include PPAs accounted for as executory contracts.
	(b)	PPA operating leases contractually expire through 2033.
Asset Retirement Obligations	'
	A reconciliation of SPS’ AROs is shown in the tables below for the years ended Dec. 31, 2013 and 2012:
	(Thousands of Dollars)		Beginning Balance Jan. 1, 2013		Liabilities			Accretion		Revisions to Prior Estimates			Ending Balance Dec. 31, 2013
					Settled
	Electric plant
	Steam production asbestos		$	10,979	$	(118	)	$	747	$	—		$	11,608
	Steam production ash containment		764		—			48		(3		)	809
	Electric distribution		5,303		—			171		630			6,104
	Other		561		—			42		251			854
	Total liability		$	17,607	$	(118	)	$	1,008	$	878		$	19,375
	(Thousands of Dollars)		Beginning Balance Jan. 1, 2012		Liabilities			Accretion		Revisions to Prior Estimates			Ending Balance Dec. 31, 2012
					Settled
	Electric plant
	Steam production asbestos		$	20,803	$	—		$	1,422	$	(11,246	)	$	10,979
	Steam production ash containment		719		—			45		—			764
	Electric distribution		5,202		—			188		(87		)	5,303
	Other		542		—			20		(1		)	561
	Total liability		$	27,266	$	—		$	1,675	$	(11,334	)	$	17,607

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 balance sheets of SPS at Dec. 31, 2013 and 2012 are:
	(Thousands of Dollars)		See	Remaining	Dec. 31, 2013				Dec. 31, 2012
			Note(s)	Amortization Period
	Regulatory Assets				Current		Noncurrent		Current		Noncurrent
	Pension and retiree medical obligations (a)		7	Various	$	17,382	$	200,158	$	15,038	$	238,398
	Recoverable deferred taxes on AFUDC recorded in plant		1	Plant lives	—		31,362		—		27,591
	Net AROs (b)		11	Plant lives	—		21,382		—		21,714
	Conservation programs (c)		1	One to six years	1,951		7,753		1,735		9,095
	Renewable resources and environmental initiatives		11	One to four years	3,428		17,671		4,094		15,101
	Losses on reacquired debt		4	Term of related debt	1,225		3,697		1,225		4,922
	Deferred income tax adjustment		1, 6	Typically plant lives	—		3,375		—		4,859
	Recoverable electric energy costs		1	Less than one year	491		—		873		—
	Other			Various	3,118		5,017		1,055		2,401
	Total regulatory assets				$	27,595	$	290,415	$	24,020	$	324,081
	(a)	Includes the non-qualified pension plan.
	(b)	Includes amounts recorded for future recovery of AROs.
	(c)	Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions.
Regulatory Liabilities	'
	The components of regulatory liabilities shown on the balance sheets of SPS at Dec. Dec. 31, 2013 and 2012 are:
	(Thousands of Dollars)		See	Remaining	Dec. 31, 2013				Dec. 31, 2012
			Note(s)	Amortization Period
	Regulatory Liabilities				Current		Noncurrent		Current		Noncurrent
	Plant removal costs		11	Plant lives	$	—	$	53,006	$	—	$	66,575
	Deferred electric energy costs		1	Less than one year	55,395		—		61,874		—
	Contract valuation adjustments (a)		1, 9	Term of related contract	14,243		6,849		4,292		11,159
	Gain from asset sales		10	Various	11,172		4,201		4,903		8,272
	Conservation programs (b)		1	Less than one year	1,465		—		1,875		—
	Other			Various	1,484		17,448		2,947		5,809
	Total regulatory liabilities				$	83,759	$	81,504	$	75,891	$	91,815
	(a)	Includes the fair value of certain long-term PPAs used to meet energy capacity requirements.
	(b)	Includes costs for conservation programs as well as incentives allowed in certain jurisdictions.

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		$	(1,332	)
	Losses reclassified from net accumulated other comprehensive loss		171
	Net current period OCI		171
	Accumulated other comprehensive loss at Dec. 31		$	(1,161	)
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		$	268		(a)
	Total, pre-tax		268
	Tax benefit		(97		)
	Total amounts reclassified, net of tax		$	171
	(a)	Included in interest charges.

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 for the years ended Dec. 31:
	(Thousands of Dollars)	2013		2012		2011
	Operating revenues:
	Electric	$	1,331	$	6,539	$	7,187
	Operating expenses:
	Purchased power	8,136		9,271		10,896
	Other operating expenses — paid to Xcel Energy Services Inc.	127,669		117,277		118,370
	Interest expense	178		76		83
	Interest income	—		10		1
	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	$	3,462	$	—	$	3,820	$	—
	NSP-Wisconsin	—		26		4		—
	PSCo	—		1,056		—		69
	Other subsidiaries of Xcel Energy Inc.	12,378		14,305		967		12,294
		$	15,840	$	15,387	$	4,791	$	12,363

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	$	374,257	$	461,831	$	481,407	$	389,592
	Operating income	33,059		58,469		74,653		43,836
	Net income	12,584		28,206		35,037		19,350
		Quarter Ended
	(Thousands of Dollars)	March 31, 2012		June 30, 2012		Sept. 30, 2012		Dec. 31, 2012
	Operating revenues	$	340,488	$	380,201	$	471,889	$	347,477
	Operating income	31,845		61,891		107,509		24,510
	Net income	11,360		30,294		58,247		6,468

Summary_of_Significant_Account2

Summary of Significant Accounting Policies (Details)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Conservation Programs [Abstract]	'	'	'
Maximum number of months following end of annual period in which revenues are earned to be included in incentive programs (in months)	'24 months	'	'
Property, Plant and Equipment and Depreciation [Abstract]	'	'	'
Depreciation expense expressed as a percentage of average depreciable property (in hundredths)	2.60%	2.70%	2.70%
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_De

Selected Balance Sheet Data (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Accounts receivable, net	'	'
Accounts receivable	$76,426	$66,789
Less allowance for bad debts	-5,475	-4,722
Accounts receivable, net	$70,951	$62,067

Selected_Balance_Sheet_Data_Ba

Selected Balance Sheet Data Balance Sheet Related Disclosures, Inventories (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Public Utilities, Inventory [Line Items]	'	'
Inventories	$37,138	$31,337
Materials and supplies	'	'
Public Utilities, Inventory [Line Items]	'	'
Inventories	21,600	18,129
Fuel	'	'
Public Utilities, Inventory [Line Items]	'	'
Inventories	$15,538	$13,208

Selected_Balance_Sheet_Data_Ba1

Selected Balance Sheet Data Balance Sheet Related Disclosures, 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	$5,102,721	$4,616,344
Less accumulated depreciation	-1,818,691	-1,754,588
Property, plant and equipment, net	3,284,030	2,861,756
Electric plant	'	'
Public Utility, Property, Plant and Equipment [Line Items]	'	'
Property, plant and equipment, gross	4,714,398	4,379,208
Construction work in progress	'	'
Public Utility, Property, Plant and Equipment [Line Items]	'	'
Property, plant and equipment, gross	$388,323	$237,136

Borrowings_and_Other_Financing2

Borrowings and Other Financing Instruments, Short-Term Borrowings (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	$84,000,000	$84,000,000	$9,000,000	'
Money Pool	'	'	'	'
Short-term Debt [Line Items]	'	'	'	'
Borrowing limit	100,000,000	100,000,000	100,000,000	100,000,000
Amount outstanding at period end	38,000,000	38,000,000	0	5,000,000
Average amount outstanding	65,000,000	46,000,000	10,000,000	12,000,000
Maximum amount outstanding	100,000,000	100,000,000	63,000,000	71,000,000
Weighted average interest rate, computed on a daily basis (in hundredths)	0.18%	0.15%	0.33%	0.35%
Weighted average interest rate at period end (in hundredths)	0.25%	0.25%	'	0.35%
Commercial Paper	'	'	'	'
Short-term Debt [Line Items]	'	'	'	'
Borrowing limit	300,000,000	300,000,000	300,000,000	300,000,000
Amount outstanding at period end	84,000,000	84,000,000	9,000,000	0
Average amount outstanding	60,000,000	32,000,000	18,000,000	54,000,000
Maximum amount outstanding	$121,000,000	$140,000,000	$106,000,000	$161,000,000
Weighted average interest rate, computed on a daily basis (in hundredths)	0.30%	0.30%	0.39%	0.37%
Weighted average interest rate at period end (in hundredths)	0.27%	0.27%	0.36%	'

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	$25,500,000	$0

Borrowings_and_Other_Financing4

Borrowings and Other Financing Instruments, Credit Facility (Details) (USD $)	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012
Debt Disclosure [Abstract]	'		'
Credit agreement term (in years)	'5 years		'
Number Of Additional Periods Revolving Termination Date Can Be Extended Subject To Majority Bank Group Approval	2		'
Term Of Each Additional Period Revolving Termination Date Can Be Extended Subject To Majority Bank Group Approval	'1 year		'
Line Of Credit Facility Maximum Amount Credit Facility May Be Increased	$50,000,000		'
Line Of Credit Facility Maximum Debt To Total Capitalization Ratio Allowed	65.00%		'
Line Of Credit Facility Debt To Total Capitalization Ratio	49.00%		'
Line Of Credit Facility Minimum Threshhold Percentage Of Subsidiary Assets To Consolidated Assets Required To Initiate Cross Default Provisions	15.00%		'
Line of Credit Facility, Minimum Amount of Indebtedness in Default to Initiate Cross Default Provisions	75,000,000		'
Credit Facility [Abstract]	'		'
Credit facility	300,000,000	[1]	'
Drawn	109,500,000	[2]	'
Available	190,500,000		'
Credit facility bank borrowings 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 and letters of credit.

Borrowings_and_Other_Financing5

Borrowings and Other Financing Instruments, Long-Term Borrowings (Details) (USD $)	1 Months Ended		12 Months Ended
	Aug. 31, 2013	Jun. 30, 2012	Dec. 31, 2013	Dec. 31, 2012
Debt Instrument [Line Items]	'	'	'	'
Long-term Debt, Maturities, Repayments of Principal in Year Three	'	'	$200,000,000	'
Long-term Debt, Maturities, Repayments of Principal in Year Five	'	'	250,000,000	'
Deferred Finance Costs, Noncurrent, Net	'	'	10,300,000	9,700,000
Equity to total capitalization ratio (excluding short-term debt), low end of range	'	'	45.00%	'
Equity to total capitalization ratio (excluding short-term debt), high end of range	'	'	55.00%	'
Equity to total capitalization ratio (excluding short-term debt)	'	'	53.20%	'
Unrestricted Retained Earnings Per State Regulatory Commissions Dividend Restrictions	'	'	359,000,000	'
First Mortgage Bonds | Series Due Aug. 15, 2041	'	'	'	'
Debt Instrument [Line Items]	'	'	'	'
Face amount	100,000,000	100,000,000	'	'
Debt instrument, interest rate stated percentage (in hundredths)	4.50%	4.50%	4.50%	'
Maturity date	15-Aug-41	15-Aug-41	15-Aug-41	'
Principal outstanding	'	'	$400,000,000	$300,000,000

Preferred_Stock_Details

Preferred Stock (Details) (USD $)	Dec. 31, 2013
Equity [Abstract]	'
Preferred stock, shares authorized (in shares)	10,000,000
Preferred stock, par value (in dollars per share)	$1
Preferred stock, shares outstanding (in shares)	0

Income_Taxes_Details

Income Taxes (Details) (USD $)	12 Months Ended			1 Months Ended	3 Months Ended	12 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	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
Tax Audits [Abstract]	'	'	'	'	'	'	'	'	'
Year(s) no longer subject to audit as statute of limitations has expired	'	'	'	'	'	'2008	'	'	'
Earliest year subject to examination	'	'	'	'	'	'2009	'	'2008	'
Year(s) under examination	'	'	'	'	'2010 and 2011	'	'	'	'
Tax Adjustments, Settlements, and Unusual Provisions	'	'	'	$10,000,000	'	'	'	'	'
Operating Loss Carryforwards	'	'	'	168,700,000	'	168,700,000	158,000,000	23,600,000	21,000,000
Tax Credit Carryforward, Amount	'	'	'	1,700,000	'	1,700,000	1,300,000	'	'
Carryforward expiration date range, low	'	'	'	'	'	'2021	'	'2014	'
Carryforward expiration date range, high	'	'	'	'	'	'2033	'	'2031	'
Unrecognized Tax Benefits [Abstract]	'	'	'	'	'	'	'	'	'
Unrecognized tax benefit b Permanent tax positions	1,200,000	200,000	'	'	'	'	'	'	'
Unrecognized tax benefit b Temporary tax positions	2,900,000	3,700,000	'	'	'	'	'	'	'
Total unrecognized tax benefit	4,100,000	3,900,000	4,800,000	'	'	'	'	'	'
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]	'	'	'	'	'	'	'	'	'
Balance at Jan. 1	3,900,000	4,800,000	4,300,000	'	'	'	'	'	'
Unrecognized Tax Benefits, Increase Resulting from Current Period Tax Positions	1,600,000	1,100,000	1,500,000	'	'	'	'	'	'
Unrecognized Tax Benefits, Decrease Resulting from Current Period Tax Positions	0	-1,600,000	-200,000	'	'	'	'	'	'
Unrecognized Tax Benefits Increases Resulting From Prior Period Tax Positions	3,100,000	800,000	2,500,000	'	'	'	'	'	'
Unrecognized Tax Benefits Decreases Resulting From Prior Period Tax Positions	-300,000	-1,200,000	-300,000	'	'	'	'	'	'
Unrecognized Tax Benefits, Decrease Resulting from Settlements with Taxing Authorities	-4,200,000	0	-3,000,000	'	'	'	'	'	'
Balance at Dec. 31	4,100,000	3,900,000	4,800,000	'	'	'	'	'	'
Tax Benefits Associated With NOL And Tax Credit Carryforwards [Abstract]	'	'	'	'	'	'	'	'	'
NOL and tax credit carryforwards	-2,400,000	-2,000,000	'	'	'	'	'	'	'
Upper bound of decrease in unrecognized tax benefit that is reasonably possible	-2,000,000	'	'	'	'	'	'	'	'
Amounts accrued for penalties related to unrecognized tax benefits	0	0	0	'	'	'	'	'	'
Effective Income Tax Rate Reconciliation, Percent [Abstract]	'	'	'	'	'	'	'	'	'
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent	35.00%	35.00%	35.00%	'	'	'	'	'	'
Effective Income Tax Rate Reconciliation, State and Local Income Taxes, Percent	2.00%	2.20%	2.90%	'	'	'	'	'	'
Effective Income Tax Rate Reconciliation Change In Unrecognized Tax Benefits	0.70%	0.00%	0.00%	'	'	'	'	'	'
Effective Income Tax Rate Reconciliation Regulatory Differences Utility Plant Items	-1.10%	-0.40%	-0.10%	'	'	'	'	'	'
Effective Income Tax Rate Reconciliation, Tax Credit, Percent	-0.40%	-0.20%	-0.30%	'	'	'	'	'	'
Effective Income Tax Rate Reconciliation, Other Adjustments, Percent	-0.10%	0.30%	0.50%	'	'	'	'	'	'
Effective Income Tax Rate Reconciliation, Percent	36.10%	36.90%	38.00%	'	'	'	'	'	'
Components of Income Tax Expense (Benefit), Continuing Operations [Abstract]	'	'	'	'	'	'	'	'	'
Current Federal Tax Expense (Benefit)	14,947,000	6,549,000	-1,993,000	'	'	'	'	'	'
Current State and Local Tax Expense (Benefit)	2,943,000	2,712,000	3,287,000	'	'	'	'	'	'
Current Change In Unrecognized Tax Expense (Benefit)	-263,000	-824,000	-1,394,000	'	'	'	'	'	'
Deferred Federal Income Tax Expense (Benefit)	33,489,000	50,189,000	50,903,000	'	'	'	'	'	'
Deferred State and Local Income Tax Expense (Benefit)	1,754,000	3,069,000	3,240,000	'	'	'	'	'	'
Deferred Change In Unrecognized Tax Expense (Benefit)	1,232,000	861,000	1,365,000	'	'	'	'	'	'
Deferred investment tax credits	-341,000	-327,000	-275,000	'	'	'	'	'	'
Income Tax Expense (Benefit)	53,761,000	62,229,000	55,133,000	'	'	'	'	'	'
Deferred Income Tax Expense (Benefit), Continuing Operations [Abstract]	'	'	'	'	'	'	'	'	'
Deferred tax expense (benefit) excluding selected items	38,333,000	55,749,000	56,181,000	'	'	'	'	'	'
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities	-1,761,000	-1,533,000	-575,000	'	'	'	'	'	'
Other Comprehensive Income (Loss), Tax	-97,000	-97,000	-98,000	'	'	'	'	'	'
Deferred Income Tax Expense (Benefit)	36,475,000	54,119,000	55,508,000	'	'	'	'	'	'
Deferred Tax Liabilities, Gross [Abstract]	'	'	'	'	'	'	'	'	'
Deferred Tax Liabilities, Property, Plant and Equipment	705,416,000	654,259,000	'	'	'	'	'	'	'
Deferred Tax Assets, Tax Deferred Expense, Compensation and Benefits, Employee Benefits	52,081,000	51,394,000	'	'	'	'	'	'	'
Deferred Tax Liabilities, Other	30,066,000	24,034,000	'	'	'	'	'	'	'
Deferred Tax Liabilities, Net	787,563,000	729,687,000	'	'	'	'	'	'	'
Deferred Tax Assets, Gross [Abstract]	'	'	'	'	'	'	'	'	'
Deferred Tax Assets, Operating Loss Carryforwards	61,330,000	59,562,000	'	'	'	'	'	'	'
Deferred Tax Assets Rate Refund	17,192,000	2,911,000	'	'	'	'	'	'	'
Deferred Tax Assets Unbilled Revenue Fuel Costs	13,316,000	10,555,000	'	'	'	'	'	'	'
Deferred Tax Assets Regulatory Liabilities	9,724,000	6,176,000	'	'	'	'	'	'	'
Deferred Tax Assets, Tax Deferred Expense, Deferred Fuel Costs	6,877,000	11,952,000	'	'	'	'	'	'	'
Deferred Tax Assets, Other	6,708,000	4,448,000	'	'	'	'	'	'	'
Deferred Tax Assets, Net of Valuation Allowance	115,147,000	95,604,000	'	'	'	'	'	'	'
Deferred Tax Assets, Net	$672,416,000	$634,083,000	'	'	'	'	'	'	'

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)	65.00%
Number of bargaining employees receiving benefits under several collective bargaining agreements	832

Benefit_Plans_and_Other_Postre3

Benefit Plans and Other Postretirement Benefits Benefit 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
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Supplemental Executive Retirement Plan (SERP) and Nonqualified Pension Plan	'	'	'
Pension Benefits [Abstract]	'	'	'
Total benefit obligation	$2,800	$3,300	'
Net benefit cost recognized for financial reporting	300	300	'
Minimum number of years historical achieved weighted average annual returns are used to determine investment return assumptions (in years)	'20 years	'	'
Pension Plans	'	'	'
Pension Benefits [Abstract]	'	'	'
Total benefit obligation	434,307	454,184	403,367
Net benefit cost recognized for financial reporting	20,302	13,324	9,661
Expected average long-term rate of return on assets (in hundredths)	6.49%	6.68%	6.80%
Expected average long-term rate of return on assets for next fiscal year (in hundredths)	6.90%	'	'
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)	29.00%	21.00%	'
Pension Plans | Long-duration fixed income and interest rate swap securities	'	'	'
Target Pension Asset Allocations [Abstract]	'	'	'
Target pension asset allocations (in hundredths)	36.00%	50.00%	'
Pension Plans | Short-to-intermediate fixed income securities	'	'	'
Target Pension Asset Allocations [Abstract]	'	'	'
Target pension asset allocations (in hundredths)	14.00%	8.00%	'
Pension Plans | Alternative investments	'	'	'
Target Pension Asset Allocations [Abstract]	'	'	'
Target pension asset allocations (in hundredths)	19.00%	19.00%	'
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	39,400	'
Net benefit cost recognized for financial reporting	$6,600	$15,600	'

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	$393,393	$376,138	$350,054	'
Level 1	'	'	'	'
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]	'	'	'	'
Fair value of plan assets	30,167	34,527	'	'
Level 2	'	'	'	'
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]	'	'	'	'
Fair value of plan assets	339,249	311,507	'	'
Level 3	'	'	'	'
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]	'	'	'	'
Fair value of plan assets	23,977	30,104	31,670	36,106
Cash equivalents	'	'	'	'
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]	'	'	'	'
Fair value of plan assets	17,354	26,765	'	'
Cash equivalents | Level 1	'	'	'	'
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]	'	'	'	'
Fair value of plan assets	17,354	26,765	'	'
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	4,200	1,388	'	'
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	4,200	1,388	'	'
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	26,649	33,676	'	'
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	26,649	33,676	'	'
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	79,635	95,726	'	'
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	79,635	95,726	'	'
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	889	1,755	4,018	'
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	889	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	1,755	4,018	3,450
Mortgage-backed securities	'	'	'	'
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]	'	'	'	'
Fair value of plan assets	1,939	4,331	7,907	'
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	1,939	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	4,331	7,907	11,060
Common stock	'	'	'	'
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]	'	'	'	'
Fair value of plan assets	12,813	7,762	'	'
Common stock | Level 1	'	'	'	'
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]	'	'	'	'
Fair value of plan assets	12,813	7,762	'	'
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	18,222	17,049	16,159	'
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	18,222	17,049	16,159	11,464
Commingled funds	'	'	'	'
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]	'	'	'	'
Fair value of plan assets	223,322	183,957	'	'
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	223,322	183,957	'	'
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	5,755	6,969	3,586	'
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	5,755	6,969	3,586	10,132
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	2,615	-3,240	'	'
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	2,615	-3,240	'	'
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	$393,393		$376,138	$350,054
Level 3	'		'	'
Changes in Level 3 Plan Assets [Roll Forward]	'		'	'
Fair value of plan assets at Jan. 1	30,104		31,670	36,106
Net realized gains (losses)	2,308		2,664	838
Net unrealized gains (losses)	420		-2,751	3,211
Purchases, issuances and settlements, net	726		-1,479	-8,485
Transfers in (out) of Level 3	-9,581	[1]	0	0
Fair value of plan assets at Dec. 31	23,977		30,104	31,670
Asset-backed securities	'		'	'
Changes in Level 3 Plan Assets [Roll Forward]	'		'	'
Fair value of plan assets at Dec. 31	889		1,755	4,018
Asset-backed securities | Level 3	'		'	'
Changes in Level 3 Plan Assets [Roll Forward]	'		'	'
Fair value of plan assets at Jan. 1	1,755		4,018	3,450
Net realized gains (losses)	0		531	328
Net unrealized gains (losses)	0		-741	-355
Purchases, issuances and settlements, net	0		-2,053	595
Transfers in (out) of Level 3	-1,755	[1]	0	0
Fair value of plan assets at Dec. 31	0		1,755	4,018
Mortgage-backed securities	'		'	'
Changes in Level 3 Plan Assets [Roll Forward]	'		'	'
Fair value of plan assets at Dec. 31	1,939		4,331	7,907
Mortgage-backed securities | Level 3	'		'	'
Changes in Level 3 Plan Assets [Roll Forward]	'		'	'
Fair value of plan assets at Jan. 1	4,331		7,907	11,060
Net realized gains (losses)	0		245	170
Net unrealized gains (losses)	0		-265	-865
Purchases, issuances and settlements, net	0		-3,556	-2,458
Transfers in (out) of Level 3	-4,331	[1]	0	0
Fair value of plan assets at Dec. 31	0		4,331	7,907
Private equity investments	'		'	'
Changes in Level 3 Plan Assets [Roll Forward]	'		'	'
Fair value of plan assets at Dec. 31	18,222		17,049	16,159
Private equity investments | Level 3	'		'	'
Changes in Level 3 Plan Assets [Roll Forward]	'		'	'
Fair value of plan assets at Jan. 1	17,049		16,159	11,464
Net realized gains (losses)	2,630		1,886	401
Net unrealized gains (losses)	-1,055		-2,296	1,300
Purchases, issuances and settlements, net	-402		1,300	2,994
Transfers in (out) of Level 3	0	[1]	0	0
Fair value of plan assets at Dec. 31	18,222		17,049	16,159
Real estate	'		'	'
Changes in Level 3 Plan Assets [Roll Forward]	'		'	'
Fair value of plan assets at Dec. 31	5,755		6,969	3,586
Real estate | Level 3	'		'	'
Changes in Level 3 Plan Assets [Roll Forward]	'		'	'
Fair value of plan assets at Jan. 1	6,969		3,586	10,132
Net realized gains (losses)	-322		2	-61
Net unrealized gains (losses)	1,475		551	3,131
Purchases, issuances and settlements, net	1,128		2,830	-9,616
Transfers in (out) of Level 3	-3,495	[1]	0	0
Fair value of plan assets at Dec. 31	$5,755		$6,969	$3,586
[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	'	$402,509,000		$416,808,000		'
Change in Projected Benefit Obligation [Roll Forward]	'	'		'		'
Obligation at Jan. 1	434,307,000	454,184,000		403,367,000		'
Service cost	'	9,615,000		8,520,000		7,690,000
Interest cost	'	17,908,000		19,697,000		20,036,000
Plan amendments	'	0		98,000		'
Actuarial (gain) loss	'	-27,185,000		45,881,000		'
Transfer from other plan	'	3,625,000		0		'
Benefit payments	'	-23,840,000		-23,379,000		'
Obligation at Dec. 31	'	434,307,000		454,184,000		403,367,000
Change in Fair Value of Plan Assets [Roll Forward]	'	'		'		'
Fair value of plan assets at Jan. 1	393,393,000	376,138,000		350,054,000		'
Actual return (loss) on plan assets	'	15,455,000		36,403,000		'
Employer contributions	'	22,015,000		13,060,000		'
Transfer from other plan	'	3,625,000		0		'
Benefit payments	'	-23,840,000		-23,379,000		'
Fair value of plan assets at Dec. 31	'	393,393,000		376,138,000		350,054,000
Funded Status of Plans at Dec. 31 [Abstract]	'	'		'		'
Funded status	'	-40,914,000	[1]	-78,046,000	[1]	'
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost [Abstract]	'	'		'		'
Net loss	'	208,594,000		244,412,000		'
Prior service (credit) cost	'	93,000		963,000		'
Total	'	208,687,000		245,375,000		'
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	'	15,843,000		14,877,000		'
Noncurrent regulatory assets	'	192,844,000		230,498,000		'
Total	'	208,687,000		245,375,000		'
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	4,400,000	22,000,000		13,100,000		5,200,000
Components of Net Periodic Benefit Cost (Credit) [Abstract]	'	'		'		'
Service cost	'	9,615,000		8,520,000		7,690,000
Interest cost	'	17,908,000		19,697,000		20,036,000
Expected return on plan assets	'	-23,970,000		-24,928,000		-26,316,000
Amortization of prior service cost (credit)	'	870,000		1,438,000		1,505,000
Amortization of net (gain) loss	'	17,148,000		12,897,000		9,046,000
Net periodic benefit cost	'	21,571,000		17,624,000		11,961,000
(Costs) credits not recognized due to effects of regulation	'	-1,269,000		-4,300,000		-2,300,000
Net benefit cost recognized for financial reporting	'	20,302,000		13,324,000		9,661,000
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)	'	6.49%		6.68%		6.80%
Allocated costs for pension plans sponsored by Xcel Energy Services Inc.	'	4,900,000		4,100,000		2,900,000
Expected average long-term rate of return on assets for next fiscal year (in hundredths)	'	6.90%		'		'
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 SPSb 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	$2.40	$2.30	$2

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	$46,738	$46,222	$39,679	'
Level 1	'	'	'	'
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]	'	'	'	'
Fair value of plan assets	1,941	8,774	'	'
Level 2	'	'	'	'
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]	'	'	'	'
Fair value of plan assets	44,797	33,534	'	'
Level 3	'	'	'	'
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]	'	'	'	'
Fair value of plan assets	0	3,914	3,265	2,065
Cash equivalents	'	'	'	'
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]	'	'	'	'
Fair value of plan assets	1,941	8,774	'	'
Cash equivalents | Level 1	'	'	'	'
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]	'	'	'	'
Fair value of plan assets	1,941	8,774	'	'
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	-38	'	'	'
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	-38	'	'	'
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	5,549	7,061	'	'
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	5,549	7,061	'	'
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	5,016	4,807	'	'
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	5,016	4,807	'	'
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	4,926	4,211	'	'
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	4,926	4,211	'	'
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	319	73	'	'
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	319	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	73	730	245
Mortgage-backed securities	'	'	'	'
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]	'	'	'	'
Fair value of plan assets	2,303	3,841	'	'
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	2,303	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	3,841	2,535	1,820
Commingled funds	'	'	'	'
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]	'	'	'	'
Fair value of plan assets	28,331	21,958	'	'
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	28,331	21,958	'	'
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	-1,609	-4,503	'	'
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	-1,609	-4,503	'	'
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	$46,738		$46,222	$39,679
Level 3	'		'	'
Changes in Level 3 Plan Assets [Roll Forward]	'		'	'
Fair value of plan assets at Jan. 1	3,914		3,265	2,065
Net realized gains (losses)	0		-102	-159
Net unrealized gains (losses)	0		556	93
Purchases, issuances and settlements, net	0		195	1,266
Transfers in (out) of Level 3	-3,914	[1]	0	'
Fair value of plan assets at Dec. 31	0		3,914	3,265
Asset-backed securities	'		'	'
Changes in Level 3 Plan Assets [Roll Forward]	'		'	'
Fair value of plan assets at Dec. 31	319		73	'
Asset-backed securities | Level 3	'		'	'
Changes in Level 3 Plan Assets [Roll Forward]	'		'	'
Fair value of plan assets at Jan. 1	73		730	245
Net realized gains (losses)	0		-32	-2
Net unrealized gains (losses)	0		179	-101
Purchases, issuances and settlements, net	0		-804	588
Transfers in (out) of Level 3	-73	[1]	0	'
Fair value of plan assets at Dec. 31	0		73	730
Mortgage-backed securities	'		'	'
Changes in Level 3 Plan Assets [Roll Forward]	'		'	'
Fair value of plan assets at Dec. 31	2,303		3,841	'
Mortgage-backed securities | Level 3	'		'	'
Changes in Level 3 Plan Assets [Roll Forward]	'		'	'
Fair value of plan assets at Jan. 1	3,841		2,535	1,820
Net realized gains (losses)	0		-70	-157
Net unrealized gains (losses)	0		377	194
Purchases, issuances and settlements, net	0		999	678
Transfers in (out) of Level 3	-3,841	[1]	0	'
Fair value of plan assets at Dec. 31	$0		$3,841	$2,535
[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) (Postretirement Benefit Plan, USD $)	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Change in Projected Benefit Obligation [Roll Forward]	'		'		'
Obligation at Jan. 1	$59,260,000		$55,165,000		'
Service cost	1,368,000		1,259,000		1,092,000
Interest cost	2,352,000		2,831,000		2,722,000
Medicare subsidy reimbursements	63,000		404,000		'
Plan amendments	0		-4,334,000		'
Plan participants' contributions	698,000		2,004,000		'
Actuarial (gain) loss	-5,215,000		7,120,000		'
Benefit payments	-3,544,000		-5,189,000		'
Obligation at Dec. 31	54,982,000		59,260,000		55,165,000
Change in Fair Value of Plan Assets [Roll Forward]	'		'		'
Fair value of plan assets at Jan. 1	46,222,000		39,679,000		'
Actual return (loss) on plan assets	3,228,000		5,375,000		'
Plan participants' contributions	698,000		2,004,000		'
Employer contributions	134,000		4,353,000		'
Benefit payments	-3,544,000		-5,189,000		'
Fair value of plan assets at Dec. 31	46,738,000		46,222,000		39,679,000
Funded Status of Plans at Dec. 31 [Abstract]	'		'		'
Funded status	-8,244,000	[1]	-13,038,000	[1]	'
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost [Abstract]	'		'		'
Net loss	-5,344,000		-90,000		'
Prior service (credit) cost	-3,833,000		-4,317,000		'
Transition obligation	0		0		'
Total	-9,177,000		-4,407,000		'
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 liabilities	-319,000		-954,000		'
Noncurrent regulatory liabilities	-8,858,000		-3,453,000		'
Total	-9,177,000		-4,407,000		'
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	5,684,000		'		'
One-percent decrease in APBO	-4,763,000		'		'
One-percent increase in service and interest components	368,000		'		'
One-percent decrease in service and interest components	-290,000		'		'
Cash Flows [Abstract]	'		'		'
Total contributions to Xcel Energy's postretirement health care plans during the year	100,000		4,400,000		3,600,000
Expected contribution to postretirement health care plans during 2014	0		'		'
Components of Net Periodic Benefit Cost (Credit) [Abstract]	'		'		'
Service cost	1,368,000		1,259,000		1,092,000
Interest cost	2,352,000		2,831,000		2,722,000
Expected return on plan assets	-3,183,000		-2,701,000		-3,006,000
Amortization of transition obligation	0		1,545,000		1,669,000
Amortization of prior service cost (credit)	-484,000		-148,000		-51,000
Amortization of net (gain) loss	-6,000		1,256,000		855,000
Net periodic benefit cost	47,000		4,042,000		3,281,000
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.	'		'		'
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		'		'
[1]	Amounts are recognized in noncurrent liabilities on SPSb balance sheet.

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	$26,265
2015	27,361
2016	27,565
2017	28,738
2018	29,703
2019-2023	153,507
Postretirement Benefit Plan	'
Defined Benefit Plan, Gross Projected Benefit Payments [Abstract]	'
2014	3,285
2015	3,450
2016	3,547
2017	3,691
2018	3,582
2019-2023	17,912
Expected Medicare Part D Subsidies [Abstract]	'
2014	33
2015	36
2016	50
2017	52
2018	55
2019-2023	186
Defined Benefit Plan, Net Projected Benefit Payments [Abstract]	'
2014	3,252
2015	3,414
2016	3,497
2017	3,639
2018	3,527
2019-2023	$17,726

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	$663	$379	$506
Other nonoperating income	9	36	11
Insurance policy expense	-532	-369	-111
Other income, net	$140	$46	$406

Fair_Value_of_Financial_Assets2

Fair Value of Financial Assets and Liabilities, Derivative Instruments (Details) (USD $)	Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2013
In Millions, unless otherwise specified	Commodity Derivatives, Net [Member]	Credit Concentration Risk [Member]	Credit Concentration Risk [Member]	Credit Concentration Risk [Member]	Credit Concentration Risk [Member]	Interest Rate Swap [Member]	Electric Commodity [Member]
	Contract	Counterparty	Investment Grade Ratings from Standard & Poor's, Moody's, or Fitch Ratings [Member]	No Investment Grade Ratings from External Credit Rating Agencies [Member]	Credit Quality Less Than Investment Grade [Member]		MWh
			Counterparty	Counterparty	Counterparty
Derivative [Line Items]	'	'	'	'	'	'	'
Derivative, Nonmonetary Notional Amount	'	'	'	'	'	'	5,989,000	[1]
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	'	'	'	'	'	($0.20)	'
Consideration of Credit Risk and Concentrations [Abstract]	'	'	'	'	'	'	'
Number of most significant counterparties for wholesale activities with credit exposure	'	10	2	7	1	'	'
Wholesale credit exposure for most significant counterparties	'	'	$13.50	$37.40	$3.30	'	'
Percentage of wholesale credit exposure for most significant counterparties (in hundredths)	'	'	18.00%	51.00%	5.00%	'	'
Commodity Derivatives [Abstract]	'	'	'	'	'	'	'
Number of commodity derivatives	0	'	'	'	'	'	'
[1]	Amounts are not reflective of net positions in the underlying commodities.

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	($1,332)	($1,504)	($1,675)
After-tax net realized losses on derivative transactions reclassified into earnings	171	172	171
Accumulated other comprehensive loss related to cash flow hedges at Dec. 31	($1,161)	($1,332)	($1,504)

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
Recognized gains (losses) from fair value hedges or related hedged transactions	0	0	0
Cash Flow Hedging [Member] | Interest Rate Contract [Member]	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'
Pre-tax (gains) losses reclassified into income during the period from accumulated other comprehensive loss	300,000	300,000	300,000
Not Designated as Hedging Instrument [Member] | Electric Commodity Contract [Member]	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities	$9,900,000	'	'

Fair_Value_of_Financial_Assets5

Fair Value of Financial Assets and Liabilities, Derivative Assets and Liabilities at Fair Value (Details) (USD $)	Dec. 31, 2013
Other Current Assets [Member]	'
Derivatives, Fair Value [Line Items]	'
Derivative Asset, Fair Value, Gross Asset	$17,826,000
Other Noncurrent Assets [Member]	'
Derivatives, Fair Value [Line Items]	'
Derivative Asset, Fair Value, Gross Asset	41,056,000
Other Current Liabilities [Member]	'
Derivatives, Fair Value [Line Items]	'
Derivative Liability, Fair Value, Gross Liability	3,583,000
Other Noncurrent Liabilities [Member]	'
Derivatives, Fair Value [Line Items]	'
Derivative Liability, Fair Value, Gross Liability	34,207,000
Netting [Member]	'
Derivatives, Fair Value [Line Items]	'
Derivative Liability, Collateral, Right to Reclaim Cash, Offset	0
Derivative Asset, Collateral, Obligation to Return Cash, Offset	0
Fair Value Measured on a Recurring Basis [Member] | Other Current Assets [Member] | Not Designated as Hedging Instrument [Member]	'
Derivatives, Fair Value [Line Items]	'
Derivative Asset, Fair Value, Gross Asset	9,933,000
Fair Value Measured on a Recurring Basis [Member] | Other Current Assets [Member] | Not Designated as Hedging Instrument [Member] | Electric Commodity Contract [Member]	'
Derivatives, Fair Value [Line Items]	'
Derivative Asset, Fair Value, Gross Asset	9,933,000
Fair Value Measured on a Recurring Basis [Member] | Other Current Liabilities [Member] | Not Designated as Hedging Instrument [Member]	'
Derivatives, Fair Value [Line Items]	'
Derivative Liability, Fair Value, Gross Liability	0
Fair Value Measured on a Recurring Basis [Member] | Other Current Liabilities [Member] | Not Designated as Hedging Instrument [Member] | Electric Commodity Contract [Member]	'
Derivatives, Fair Value [Line Items]	'
Derivative Liability, Fair Value, Gross Liability	0
Fair Value Measured on a Recurring Basis [Member] | Level 1 | Other Current Assets [Member] | Not Designated as Hedging Instrument [Member]	'
Derivatives, Fair Value [Line Items]	'
Derivative Asset, Fair Value, Gross Asset	0
Fair Value Measured on a Recurring Basis [Member] | Level 1 | Other Current Assets [Member] | Not Designated as Hedging Instrument [Member] | Electric Commodity Contract [Member]	'
Derivatives, Fair Value [Line Items]	'
Derivative Asset, Fair Value, Gross Asset	0
Fair Value Measured on a Recurring Basis [Member] | Level 1 | Other Current Liabilities [Member] | Not Designated as Hedging Instrument [Member]	'
Derivatives, Fair Value [Line Items]	'
Derivative Liability, Fair Value, Gross Liability	0
Fair Value Measured on a Recurring Basis [Member] | Level 1 | Other Current Liabilities [Member] | Not Designated as Hedging Instrument [Member] | Electric Commodity Contract [Member]	'
Derivatives, Fair Value [Line Items]	'
Derivative Liability, Fair Value, Gross Liability	0
Fair Value Measured on a Recurring Basis [Member] | Level 2 | Other Current Assets [Member] | Not Designated as Hedging Instrument [Member]	'
Derivatives, Fair Value [Line Items]	'
Derivative Asset, Fair Value, Gross Asset	0
Fair Value Measured on a Recurring Basis [Member] | Level 2 | Other Current Assets [Member] | Not Designated as Hedging Instrument [Member] | Electric Commodity Contract [Member]	'
Derivatives, Fair Value [Line Items]	'
Derivative Asset, Fair Value, Gross Asset	0
Fair Value Measured on a Recurring Basis [Member] | Level 2 | Other Current Liabilities [Member] | Not Designated as Hedging Instrument [Member]	'
Derivatives, Fair Value [Line Items]	'
Derivative Liability, Fair Value, Gross Liability	0
Fair Value Measured on a Recurring Basis [Member] | Level 2 | Other Current Liabilities [Member] | Not Designated as Hedging Instrument [Member] | Electric Commodity Contract [Member]	'
Derivatives, Fair Value [Line Items]	'
Derivative Liability, Fair Value, Gross Liability	0
Fair Value Measured on a Recurring Basis [Member] | Level 3 | Other Current Assets [Member] | Not Designated as Hedging Instrument [Member]	'
Derivatives, Fair Value [Line Items]	'
Derivative Asset, Fair Value, Gross Asset	16,420,000
Fair Value Measured on a Recurring Basis [Member] | Level 3 | Other Current Assets [Member] | Not Designated as Hedging Instrument [Member] | Electric Commodity Contract [Member]	'
Derivatives, Fair Value [Line Items]	'
Derivative Asset, Fair Value, Gross Asset	16,420,000
Fair Value Measured on a Recurring Basis [Member] | Level 3 | Other Current Liabilities [Member] | Not Designated as Hedging Instrument [Member]	'
Derivatives, Fair Value [Line Items]	'
Derivative Liability, Fair Value, Gross Liability	6,487,000
Fair Value Measured on a Recurring Basis [Member] | Level 3 | Other Current Liabilities [Member] | Not Designated as Hedging Instrument [Member] | Electric Commodity Contract [Member]	'
Derivatives, Fair Value [Line Items]	'
Derivative Liability, Fair Value, Gross Liability	6,487,000
Fair Value Measured on a Recurring Basis [Member] | Estimate of Fair Value Measurement [Member] | Other Current Assets [Member] | Not Designated as Hedging Instrument [Member]	'
Derivatives, Fair Value [Line Items]	'
Derivative Asset, Fair Value, Gross Asset	16,420,000
Fair Value Measured on a Recurring Basis [Member] | Estimate of Fair Value Measurement [Member] | Other Current Assets [Member] | Not Designated as Hedging Instrument [Member] | Electric Commodity Contract [Member]	'
Derivatives, Fair Value [Line Items]	'
Derivative Asset, Fair Value, Gross Asset	16,420,000
Fair Value Measured on a Recurring Basis [Member] | Estimate of Fair Value Measurement [Member] | Other Current Liabilities [Member] | Not Designated as Hedging Instrument [Member]	'
Derivatives, Fair Value [Line Items]	'
Derivative Liability, Fair Value, Gross Liability	6,487,000
Fair Value Measured on a Recurring Basis [Member] | Estimate of Fair Value Measurement [Member] | Other Current Liabilities [Member] | Not Designated as Hedging Instrument [Member] | Electric Commodity Contract [Member]	'
Derivatives, Fair Value [Line Items]	'
Derivative Liability, Fair Value, Gross Liability	6,487,000
Fair Value Measured on a Recurring Basis [Member] | Netting [Member] | Other Current Assets [Member] | Not Designated as Hedging Instrument [Member]	'
Derivatives, Fair Value [Line Items]	'
Derivative Asset, Fair Value, Gross Asset	-6,487,000	[1]
Fair Value Measured on a Recurring Basis [Member] | Netting [Member] | Other Current Assets [Member] | Not Designated as Hedging Instrument [Member] | Electric Commodity Contract [Member]	'
Derivatives, Fair Value [Line Items]	'
Derivative Asset, Fair Value, Gross Asset	-6,487,000	[1]
Fair Value Measured on a Recurring Basis [Member] | Netting [Member] | Other Current Liabilities [Member] | Not Designated as Hedging Instrument [Member]	'
Derivatives, Fair Value [Line Items]	'
Derivative Liability, Fair Value, Gross Liability	-6,487,000	[1]
Fair Value Measured on a Recurring Basis [Member] | Netting [Member] | Other Current Liabilities [Member] | Not Designated as Hedging Instrument [Member] | Electric Commodity Contract [Member]	'
Derivatives, Fair Value [Line Items]	'
Derivative Liability, Fair Value, Gross Liability	-6,487,000	[1]
Fair Value, Measurements, Nonrecurring [Member] | Other Current Assets [Member] | Purchased Power Agreements [Member]	'
Derivatives, Fair Value [Line Items]	'
Derivative Asset, Fair Value, Gross Asset	7,893,000	[2]
Fair Value, Measurements, Nonrecurring [Member] | Other Noncurrent Assets [Member] | Purchased Power Agreements [Member]	'
Derivatives, Fair Value [Line Items]	'
Derivative Asset, Fair Value, Gross Asset	41,056,000	[2]
Fair Value, Measurements, Nonrecurring [Member] | Other Current Liabilities [Member] | Purchased Power Agreements [Member]	'
Derivatives, Fair Value [Line Items]	'
Derivative Liability, Fair Value, Gross Liability	3,583,000	[2]
Fair Value, Measurements, Nonrecurring [Member] | Other Noncurrent Liabilities [Member] | Purchased Power Agreements [Member]	'
Derivatives, Fair Value [Line Items]	'
Derivative Liability, Fair Value, Gross Liability	$34,207,000	[2]
[1]	SPS 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. At Dec. 31, 2013, derivative assets and liabilities include no obligations to return cash collateral or rights to reclaim cash collateral. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.
[2]	In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, SPS began recording several long-term PPAs at fair value due to accounting requirements related to underlying price adjustments. As these purchases are recovered through normal regulatory recovery mechanisms in the respective jurisdictions, the changes in fair value for these contracts were offset by regulatory assets and liabilities. During 2006, SPS qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.

Fair_Value_of_Financial_Assets6

Fair Value of Financial Assets and Liabilities, Changes in Level 3 Commodity Derivatives (Details) (Details) (Commodity Derivatives, Net [Member], USD $)	12 Months Ended
	Dec. 31, 2013
Commodity Derivatives, Net [Member]	'
Changes in Level 3 Commodity Derivatives [Roll Forward]	'
Balance at beginning of period	$0
Purchases	9,933,000
Balance at end of period	9,933,000
Level 3 transfers, net	$0

Fair_Value_of_Financial_Assets7

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	$1,199,865	$1,103,684
Fair Value	'	'
Financial Liabilities, Balance Sheet Groupings [Abstract]	'	'
Long-term debt, including current portion	$1,307,035	$1,327,538

Rate_Matters_Details

Rate Matters (Details) (USD $)

12 Months Ended

1 Months Ended

0 Months Ended

1 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Mar. 31, 2013

Jan. 07, 2014

Nov. 30, 2012

Jun. 30, 2013

Jun. 30, 2013

Nov. 30, 2013

Sep. 30, 2013

Aug. 31, 2013

Jun. 30, 2013

Dec. 31, 2012

Aug. 31, 2013

Feb. 28, 2014

Jan. 31, 2014

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Oct. 31, 2013

Aug. 31, 2013

Aug. 31, 2013

Aug. 31, 2013

Apr. 30, 2012

Sale of Texas Transmission Assets

Public Utility Commission of Texas (PUCT)

Public Utility Commission of Texas (PUCT)

Public Utility Commission of Texas (PUCT)

Public Utility Commission of Texas (PUCT)

Public Utility Commission of Texas (PUCT)

New Mexico Public Regulation Commission (NMPRC)

New Mexico Public Regulation Commission (NMPRC)

New Mexico Public Regulation Commission (NMPRC)

New Mexico Public Regulation Commission (NMPRC)

New Mexico Attorney General (NMAG)

Hearing Examiner

Hearing Examiner

Federal Energy Regulatory Commission (FERC)

Federal Energy Regulatory Commission (FERC)

Federal Energy Regulatory Commission (FERC)

Federal Energy Regulatory Commission (FERC)

Federal Energy Regulatory Commission (FERC)

Federal Energy Regulatory Commission (FERC)

Federal Energy Regulatory Commission (FERC)

Federal Energy Regulatory Commission (FERC)

Facility

2014 Electric Rate Case

Electric Rate Case 2012

Electric Rate Case 2012, Settlement Rates Effective May 1, 2013

Electric Rate Case 2012, Settlement Rates Effective September 1, 2013

Transmission Cost Recovery Factor (TCRF) Rider

2014 Electric Rate Case

2014 Electric Rate Case

2014 Electric Rate Case

2014 Electric Rate Case

2014 Electric Rate Case

2014 Electric Rate Case

2014 Electric Rate Case

Sale of Texas Transmission Assets

Sale of Texas Transmission Assets

Sale of Texas Transmission Assets

Federal Energy Regulatory Commission (FERC) Orders

Federal Energy Regulatory Commission (FERC) Orders

FERC Orders, Settlement Impact Through May 31, 2015

FERC Orders, Settlement Impact Effective June 1, 2015

Wholesale Electric Rate Complaint

Subsequent Event

Subsequent Event

Subsequent Event

Customers

Shareholders

Factor

Rate Matters [Abstract]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Requested Rate Increase (Decrease), Net Amount

'

'

'

'

$52,700,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Requested Rate Increase (Decrease), Percentage

'

'

'

'

5.80%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Requested Rate Increase (Decrease), Amount

'

'

'

'

81,500,000

90,200,000

'

'

'

'

'

'

45,900,000

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Adjustment requested by public utility to rate increase (decrease) related to resetting TCRF to zero

'

'

'

'

-12,900,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Adjustment requested by public utility to rate increase (decrease) related to customer credit for gain on sale

'

'

'

'

-4,900,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Requested base revenue increase (decrease) excluding fuel clause offsets

'

'

'

'

63,700,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Adjustment requested by public utility to rate increase (decrease) related to fuel offsets

'

'

'

'

-11,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Requested Return on Equity, Percentage

'

'

'

'

10.40%

10.65%

'

'

'

10.25%

'

'

10.65%

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Requested Rate Base, Amount

'

'

'

'

1,270,000,000

1,150,000,000

'

'

'

'

'

'

479,800,000

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Requested Equity Capital Structure, Percentage

'

'

'

'

53.89%

52.00%

'

'

'

'

'

'

53.89%

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Approved Rate Increase (Decrease), Amount

'

'

'

'

'

'

37,000,000

13,800,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Portion of requested rate increase (decrease) related to depreciation expense

'

'

'

'

16,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Number of months included in test year for rate filing

'

'

'

'

'

'12 months

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Requested increase (decrease) to rider revenue

'

'

'

'

'

'

'

'

13,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Requested Rate Increase (Decrease), Amended, Amount

'

'

'

'

'

'

'

'

'

32,500,000

'

43,300,000

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Adjustment to requested rate increase (decrease) recommended by third parties related to the rate rider for renewable energy costs

'

'

'

'

'

'

'

'

'

'

-14,500,000

[1]

'

'

-8,500,000

[1]

'

'

'

'

'

'

'

'

'

'

Public Utilities, Adjustment to requested rate increase (decrease) requested by third parties related to revenue adjustments

'

'

'

'

'

'

'

'

'

'

-4,400,000

'

'

-6,400,000

'

'

'

'

'

'

'

'

'

'

Public Utilities, Adjustment recommended by third parties related to return on equity

'

'

'

'

'

'

'

'

'

'

-3,200,000

'

'

-8,100,000

'

'

'

'

'

'

'

'

'

'

Public Utilities, ROE recommended by third parties

'

'

'

'

'

'

'

'

'

'

9.80%

'

'

8.63%

'

9.73%

'

'

'

'

'

'

'

'

Public Utilities, Adjustment to requested rate increase (decrease) related to change in capital structure

'

'

'

'

'

'

'

'

'

'

-1,500,000

'

'

-1,100,000

'

'

'

'

'

'

'

'

'

'

Public Utilities, Adjustment to requested rate increase (decrease) requested by third parties related to reduced recovery for employee benefits

'

'

'

'

'

'

'

'

'

'

-2,800,000

'

'

-1,800,000

'

'

'

'

'

'

'

'

'

'

Public Utilities, Adjustment to requested rate increase (decrease) recommended by third parties related to reduced recovery for payroll expense

'

'

'

'

'

'

'

'

'

'

-100,000

'

'

-100,000

'

'

'

'

'

'

'

'

'

'

Public Utilities, Adjustment to requested rate increase (decrease) recommended by third parties related to gain on sale of assets

'

'

'

'

'

'

'

'

'

'

0

'

'

-1,700,000

'

'

'

'

'

'

'

'

'

'

Public Utilities, Adjustment to requested rate increase (decrease) recommended by third parties related to fuel clause revenue

'

'

'

'

'

'

'

'

'

'

6,000,000

'

'

0

'

'

'

'

'

'

'

'

'

'

Public Utilities, Adjustment to requested rate increase (decrease) requested by third parties related to other costs

'

'

'

'

'

'

'

'

'

'

-5,000,000

'

'

-6,600,000

'

'

'

'

'

'

'

'

'

'

Public Utilities, Rate increase (decrease) recommended by third parties

'

'

'

'

'

'

'

'

'

'

17,800,000

'

'

9,000,000

'

14,700,000

'

'

'

'

'

'

'

'

Public Utilities, portion of rate increase (decrease) recommended by third parties to be recovered in base revenue

'

'

'

'

'

'

'

'

'

'

8,800,000

'

'

-6,000,000

'

'

'

'

'

'

'

'

'

'

Public Utilities, portion of rate increase (decrease) recommended by third parties to be recovered in rider revenue

'

'

'

'

'

'

'

'

'

'

7,300,000

'

'

13,300,000

'

'

'

'

'

'

'

'

'

'

Public Utilities, portion of rate increase (decrease) recommended by third parties to be recovered in fuel cost adjustment revenue

'

'

'

'

'

'

'

'

'

'

1,700,000

'

'

1,700,000

'

'

'

'

'

'

'

'

'

'

Public Utilities, portion of revised rate increase (decrease) related to base and fuel revenue.

'

'

'

'

'

'

'

'

'

20,900,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, portion of revised rate increase (decrease) related to rider revenue

'

'

'

'

'

'

'

'

'

12,100,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, portion of revised rate increase (decrease) related to other costs

'

'

'

'

'

'

'

'

'

-500,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Public Utilities, Addition (reduction) to revised requested rate increase (decrease) recommended by third parties

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

6,200,000

'

'

'

'

'

'

'

'

Public Utilities, Equity capital structure recommended by third parties

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

53.89%

'

'

'

'

'

'

'

'

Public Utilities, rider revenue increase (decrease) recommended by third parties

'

'

'

'

'

'

'

'

'

'

'

'

'

'

12,100,000

'

'

'

'

'

'

'

'

'

Number of components included in regulatory proceeding

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2

'

'

'

Number of coincident peaks used as demand allocator, revised

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

3

3

'

'

'

Number of coincident peaks used as demand allocator, original

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

12

'

'

'

Current year pre-tax earnings impact of regulatory proceedings

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

13,600,000

'

-36,000,000

'

'

'

Public Utilities, Annual increase (decrease) in revenues resulting from regulatory proceeding

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

-6,000,000

-4,000,000

-3,100,000

Public Utilities, Base return on equity charged to customers through production formula rates, Percentage

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

10.25%

Public Utilities, Base return on equity charged to customers through transmission formula rates, Percentage

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

10.77%

Public Utilities, Base return on equity requested by customers, Percentage

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

9.15%

Public Utilities, Rate increase (decrease) requested by third parties

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

-3,300,000

Public Utilities, return on equity incentive related to transmission formula rates (in basis points)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

50

Number of substations included in purchase and sale agreement

'

'

'

2

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Proceeds from sale of transmission assets

37,118,000

0

0

'

'

'

'

'

'

'

'

'

'

'

'

'

37,100,000

'

'

'

'

'

'

'

Public Utilities, Regulatory liabilities recognized for jurisdictional gain sharing

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$7,200,000

'

'

'

'

'

'

[1]

Adjustments represent recommended deferrals, extended amortizations and moving costs from rider to fuel in base rates.

Commitments_and_Contingencies_1

Commitments and Contingencies, Capital Commitments (Details) (Capital Commitments)	12 Months Ended
	Dec. 31, 2013
Southeast New Mexico Transmission Development [Member]	'
Capital Commitments [Abstract]	'
Number of projects for which notices to construct are anticipated	4
TUCO to Woodward District Extra High Voltage Interchange	'
Capital Commitments [Abstract]	'
Voltage capacity for transmission line (in kV)	345

Commitments_and_Contingencies_2

Commitments and Contingencies, Fuel Contracts (Details) (USD $)	Dec. 31, 2013
In Millions, unless otherwise specified
Coal	'
Fuel Contracts [Abstract]	'
2014	$273.80
2015	241.5
2016	143.8
2017	36.7
2018	0
Thereafter	0
Total	695.8
Natural Gas Supply	'
Fuel Contracts [Abstract]	'
2014	20.6
2015	0
2016	0
2017	0
2018	0
Thereafter	0
Total	20.6
Natural Gas Storage and Transportation	'
Fuel Contracts [Abstract]	'
2014	23.7
2015	22.1
2016	22.1
2017	21.3
2018	15.9
Thereafter	96.1
Total	$201.20

Commitments_and_Contingencies_3

Commitments and Contingencies, Purchased Power Agreements (Details) (Capacity Payments, USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012	Dec. 31, 2011
Capacity Payments	'		'	'
Purchased Power Agreements [Abstract]	'		'	'
Payments for capacity	$38.40		$36.20	$39.70
Estimated Future Payments Under PPAs [Abstract]	'		'	'
2014	52.3		'	'
2015	56.5		'	'
2016	57		'	'
2017	58.2		'	'
2018	57.2		'	'
Thereafter	72.2		'	'
Total	$353.40	[1]	'	'
[1]	(a)B Excludes contingent energy payments for renewable energy PPAs.

Commitments_and_Contingencies_4

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, Future Minimum Payments Due [Abstract]	'		'	'
2014	$61.40		'	'
2015	53.1		'	'
2016	53.1		'	'
2017	52.2		'	'
2018	51.8		'	'
Thereafter	746.8		'	'
Purchased Power Agreements (PPAs)	'		'	'
Operating Leases [Abstract]	'		'	'
Payments for capacity for PPAs under operating lease obligations	59		56	54.4
Operating Leases, Future Minimum Payments Due [Abstract]	'		'	'
2014	58.3	[1],[2]	'	'
2015	49.9	[1],[2]	'	'
2016	49.9	[1],[2]	'	'
2017	49.9	[1],[2]	'	'
2018	49.9	[1],[2]	'	'
Thereafter	734.1	[1],[2]	'	'
Office Space and Other Equipment	'		'	'
Operating Leases [Abstract]	'		'	'
Total expenses under operating lease obligations	64.2		59.9	58.8
Operating Leases, Future Minimum Payments Due [Abstract]	'		'	'
2014	3.1		'	'
2015	3.2		'	'
2016	3.2		'	'
2017	2.3		'	'
2018	1.9		'	'
Thereafter	$12.70		'	'
[1]	PPA operating leases contractually expire through 2033.
[2]	Amounts do not include PPAs accounted for as executory contracts.

Commitments_and_Contingencies_5

Commitments and Contingencies, Variable Interest Entities (Details) (Independent Power Producing Entities [Member])	Dec. 31, 2013	Dec. 31, 2012
	MW	MW
Independent Power Producing Entities [Member]	'	'
Purchased Power Agreements [Abstract]	'	'
Generating capacity (in MW)	827	827

Commitments_and_Contingencies_6

Commitments and Contingencies, Guarantees and Indemnifications (Details) (Indemnification Agreement [Member], Obligations Under Sale Of Sharyland [Member], USD $)	Dec. 31, 2013
In Millions, unless otherwise specified
Indemnification Agreement [Member] | Obligations Under Sale Of Sharyland [Member]	'
Guarantor Obligations [Line Items]	'
Guarantor Obligations, Maximum Exposure, Undiscounted	$37.10
Guarantor Obligations, Current Carrying Value	$0.40

Commitments_and_Contingencies_7

Commitments and Contingencies, Environmental Contingencies (Details)	Dec. 31, 2013	Dec. 31, 2013	Apr. 30, 2012
	Federal Clean Water Act	EPA GHG Regulation	Electric Generating Unit Mercury And Air Toxics Standards Rule
	Regulation		MW
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

Commitments_and_Contingencies_8

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	$17,607	$27,266
Liabilities settled	-118	0
Accretion	1,008	1,675
Revisions to prior estimates	878	-11,334
Ending balance	19,375	17,607
Electric Plant Steam Production Asbestos [Member]	'	'
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]	'	'
Beginning balance	10,979	20,803
Liabilities settled	-118	0
Accretion	747	1,422
Revisions to prior estimates	0	-11,246
Ending balance	11,608	10,979
Electric Plant Steam Production Ash Containment [Member]	'	'
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]	'	'
Beginning balance	764	719
Liabilities settled	0	0
Accretion	48	45
Revisions to prior estimates	-3	0
Ending balance	809	764
Electric Plant Electric Distribution [Member]	'	'
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]	'	'
Beginning balance	5,303	5,202
Liabilities settled	0	0
Accretion	171	188
Revisions to prior estimates	630	-87
Ending balance	6,104	5,303
Electric Plant Other [Member]	'	'
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]	'	'
Beginning balance	561	542
Liabilities settled	0	0
Accretion	42	20
Revisions to prior estimates	251	-1
Ending balance	$854	$561

Commitments_and_Contingencies_9

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	$53	$67

Recovered_Sheet5

Commitments and Contingencies, Legal Contingencies (Details) (Exelon Wind Complaint [Member], USD $)	Dec. 31, 2013
	Site
	Dispute
Exelon Wind Complaint [Member]	'
Legal Contingencies [Abstract]	'
Accrual for legal contingency	$0
Number of main areas of dispute	2
Number of wind facilities	12

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	$27,595,000		$24,020,000
Regulatory Asset, Noncurrent	290,415,000		324,081,000
Past expenditures not currently earning a return	30,000,000		25,000,000
Pension and Retiree Medical Obligations	'		'
Regulatory Assets [Line Items]	'		'
Regulatory Asset, Current	17,382,000	[1]	15,038,000	[1]
Regulatory Asset, Noncurrent	200,158,000	[1]	238,398,000	[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	31,362,000		27,591,000
Regulatory asset, remaining amortization period	'Plant lives		'
Net AROs	'		'
Regulatory Assets [Line Items]	'		'
Regulatory Asset, Current	0	[2]	0	[2]
Regulatory Asset, Noncurrent	21,382,000	[2]	21,714,000	[2]
Regulatory asset, remaining amortization period	'Plant lives		'
Conservation Programs	'		'
Regulatory Assets [Line Items]	'		'
Regulatory Asset, Current	1,951,000	[3]	1,735,000	[3]
Regulatory Asset, Noncurrent	7,753,000	[3]	9,095,000	[3]
Regulatory asset, remaining amortization period, minimum	'1 year		'
Regulatory asset, remaining amortization period, maximum	'6 years		'
Renewable Resources and Environmental Initiatives	'		'
Regulatory Assets [Line Items]	'		'
Regulatory Asset, Current	3,428,000		4,094,000
Regulatory Asset, Noncurrent	17,671,000		15,101,000
Regulatory asset, remaining amortization period, minimum	'1 year		'
Regulatory asset, remaining amortization period, maximum	'4 years		'
Losses on Reacquired Debt	'		'
Regulatory Assets [Line Items]	'		'
Regulatory Asset, Current	1,225,000		1,225,000
Regulatory Asset, Noncurrent	3,697,000		4,922,000
Regulatory asset, remaining amortization period	'Term of related debt		'
Deferred Income Tax Adjustment	'		'
Regulatory Assets [Line Items]	'		'
Regulatory Asset, Current	0		0
Regulatory Asset, Noncurrent	3,375,000		4,859,000
Regulatory asset, remaining amortization period	'Typically plant lives		'
Recoverable Electric Energy Costs	'		'
Regulatory Assets [Line Items]	'		'
Regulatory Asset, Current	491,000		873,000
Regulatory Asset, Noncurrent	0		0
Regulatory asset, remaining amortization period	'Less than one year		'
Other Regulatory Assets	'		'
Regulatory Assets [Line Items]	'		'
Regulatory Asset, Current	3,118,000		1,055,000
Regulatory Asset, Noncurrent	$5,017,000		$2,401,000
Regulatory asset, remaining amortization period	'Various		'
[1]	Includes the non-qualified pension plan.
[2]	Includes amounts recorded for future recovery of AROs.
[3]	Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions.

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	$83,759		$75,891
Regulatory Liability, Noncurrent	81,504		91,815
Plant Removal Costs	'		'
Regulatory Liabilities [Line Items]	'		'
Regulatory Liability, Current	0		0
Regulatory Liability, Noncurrent	53,006		66,575
Regulatory liability, remaining amortization period	'Plant lives		'
Deferred Electric Energy Costs	'		'
Regulatory Liabilities [Line Items]	'		'
Regulatory Liability, Current	55,395		61,874
Regulatory Liability, Noncurrent	0		0
Regulatory liability, remaining amortization period	'Less than one year		'
Contract Valuation Adjustments	'		'
Regulatory Liabilities [Line Items]	'		'
Regulatory Liability, Current	14,243	[1]	4,292	[1]
Regulatory Liability, Noncurrent	6,849	[1]	11,159	[1]
Regulatory liability, remaining amortization period	'Term of related contract		'
Gain From Asset Sales	'		'
Regulatory Liabilities [Line Items]	'		'
Regulatory Liability, Current	11,172		4,903
Regulatory Liability, Noncurrent	4,201		8,272
Regulatory liability, remaining amortization period	'Various		'
Conservation Programs	'		'
Regulatory Liabilities [Line Items]	'		'
Regulatory Liability, Current	1,465	[2]	1,875	[2]
Regulatory Liability, Noncurrent	0	[2]	0	[2]
Regulatory liability, remaining amortization period	'Less than one year		'
Other Regulatory Liabilities	'		'
Regulatory Liabilities [Line Items]	'		'
Regulatory Liability, Current	1,484		2,947
Regulatory Liability, Noncurrent	$17,448		$5,809
Regulatory liability, remaining amortization period	'Various		'
[1]	Includes the fair value of certain long-term PPAs used to meet energy capacity requirements.
[2]	Includes costs for conservation programs as well as incentives allowed in certain jurisdictions.

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	($1,332)		'	'
Accumulated other comprehensive loss at end of period	-1,161		-1,332	'
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]	'		'	'
Total, pre-tax	-148,938		-168,598	-145,034
Tax benefit	53,761		62,229	55,133
Gains and Losses on Cash Flow Hedges [Member]	'		'	'
Accumulated Other Comprehensive Income [Roll Forward]	'		'	'
Accumulated other comprehensive loss at beginning of period	-1,332		'	'
Losses reclassified from net accumulated other comprehensive loss	171		'	'
Net current period other comprehensive income (loss)	171		'	'
Accumulated other comprehensive loss at end of period	-1,161		'	'
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	268		'	'
Tax benefit	-97		'	'
Total, net of tax	171		'	'
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	$268	[1]	'	'
[1]	Included in interest charges.

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 [Abstract]	'	'	'
Electric	$1,331	$6,539	$7,187
Operating expenses [Abstract]	'	'	'
Purchased power	8,136	9,271	10,896
Other operating expenses - paid to Xcel Energy Services Inc.	127,669	117,277	118,370
Interest expense	178	76	83
Interest income	0	10	1
Accounts Receivable and Payable with Affiliates [Abstract]	'	'	'
Accounts receivable	15,840	4,791	'
Accounts payable	15,387	12,363	'
NSP-Minnesota	'	'	'
Accounts Receivable and Payable with Affiliates [Abstract]	'	'	'
Accounts receivable	3,462	3,820	'
Accounts payable	0	0	'
NSP-Wisconsin	'	'	'
Accounts Receivable and Payable with Affiliates [Abstract]	'	'	'
Accounts receivable	0	4	'
Accounts payable	26	0	'
PSCo	'	'	'
Accounts Receivable and Payable with Affiliates [Abstract]	'	'	'
Accounts receivable	0	0	'
Accounts payable	1,056	69	'
Other Subsidiaries of Xcel Energy Inc.	'	'	'
Accounts Receivable and Payable with Affiliates [Abstract]	'	'	'
Accounts receivable	12,378	967	'
Accounts payable	$14,305	$12,294	'

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	$389,592	$481,407	$461,831	$374,257	$347,477	$471,889	$380,201	$340,488	'	'	'
Operating income	43,836	74,653	58,469	33,059	24,510	107,509	61,891	31,845	210,017	225,755	200,597
Net income	$19,350	$35,037	$28,206	$12,584	$6,468	$58,247	$30,294	$11,360	$95,177	$106,369	$89,901

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	$4,722		$5,380		$5,095
Charged to costs and expenses	3,437		2,915		3,655
Charged to other accounts	1,076	[1]	1,202	[1]	1,139	[1]
Deductions from reserves	3,760	[2]	4,775	[2]	4,509	[2]
Balance at Dec. 31	$5,475		$4,722		$5,380
[1]	Recovery of amounts previously written off.
[2]	Principally bad debts written off.