Southwestern Public Service 10-K 24 Feb 17 2016 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2016	Feb. 24, 2017	Jun. 30, 2016
Document and Entity Information [Abstract]
Entity Registrant Name	SOUTHWESTERN PUBLIC SERVICE CO
Entity Central Index Key	92,521
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	Dec. 31, 2016
Document Fiscal Year Focus	2,016
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 ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Operating activities
Net income	$ 152,157	$ 127,263	$ 129,852
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	162,957	153,241	137,947
Demand side management program amortization	1,673	1,673	1,673
Deferred income taxes	122,983	62,836	123,517
Amortization of investment tax credits	(213)	(213)	(341)
Allowance for equity funds used during construction	(9,981)	(7,378)	(12,118)
Provision for bad debts	6,066	4,655	4,137
Net derivative losses	217	268	268
Other	122	(3,827)	0
Changes in operating assets and liabilities:
Accounts receivable	(8,868)	(3,291)	9,045
Accrued unbilled revenues	(15,637)	25,506	(20,080)
Inventories	(959)	5,686	(6,093)
Prepayments and other	22,651	(24,712)	(11,905)
Accounts payable	13,776	(24,570)	11,428
Net regulatory assets and liabilities	(55,689)	26,452	(973)
Other current liabilities	5,156	(30,762)	12,665
Pension and other employee benefit obligations	(15,276)	(9,405)	(2,246)
Change in other noncurrent assets	(200)	2,352	2,836
Change in other noncurrent liabilities	6,748	8,974	7,166
Net cash provided by operating activities	387,683	314,748	386,778
Investing activities
Utility capital/construction expenditures	(512,522)	(599,511)	(554,936)
Allowance for equity funds used during construction	9,981	7,378	12,118
Proceeds from insurance recoveries	3,901	0	0
Investments in utility money pool arrangement	(75,000)	(92,000)	(105,000)
Receipts from utility money pool arrangement	75,000	92,000	105,000
Other	(1,174)	3,136	0
Net cash used in investing activities	(499,814)	(588,997)	(542,818)
Financing activities
Proceeds from (repayment of) short-term borrowings, net	35,000	(22,000)	(47,000)
Proceeds from issuance of long-term debt	295,985	198,496	148,123
Repayment of long-term debt	(200,000)	0	0
Borrowings under utility money pool arrangement	636,500	579,700	458,000
Repayments under utility money pool arrangement	(636,500)	(595,700)	(480,000)
Capital contributions from parent	66,225	214,535	160,000
Dividends paid to parent	(85,069)	(100,544)	(83,498)
Net cash provided by financing activities	112,141	274,487	155,625
Net change in cash and cash equivalents	10	238	(415)
Cash and cash equivalents at beginning of period	834	596
Cash and cash equivalents at end of period	844	834	596
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	(78,236)	(76,474)	(70,748)
Cash paid for income taxes, net	61,813	(23,987)	42,679
Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable	$ 43,074	$ 44,335	$ 33,164

STATEMENTS OF COMMON STOCKHOLDE

STATEMENTS OF COMMON STOCKHOLDER'S EQUITY - USD ($) $ in Thousands	Total	Common stock	Additional Paid In Capital	Retained Earnings	AOCI Attributable to Parent
Beginning Balance at Dec. 31, 2013	$ 1,363,691	$ 0	$ 1,005,463	$ 359,389	$ (1,161)
Beginning Balance (in shares) at Dec. 31, 2013		100
Comprehensive income:
Net income	129,852			129,852
Other comprehensive income	172				172
Common dividends declared to parent	(93,243)			(93,243)
Contribution of capital by parent	160,000		160,000
Ending Balance at Dec. 31, 2014	1,560,472	$ 0	1,165,463	395,998	(989)
Ending Balance (in shares) at Dec. 31, 2014		100
Comprehensive income:
Net income	127,263			127,263
Other comprehensive income	(292)				(292)
Common dividends declared to parent	(85,254)			(85,254)
Contribution of capital by parent	205,760		205,760
Ending Balance at Dec. 31, 2015	$ 1,807,949	$ 0	1,371,223	438,007	(1,281)
Ending Balance (in shares) at Dec. 31, 2015	100	100
Comprehensive income:
Net income	$ 152,157			152,157
Other comprehensive income	(9)				(9)
Common dividends declared to parent	(103,401)			(103,401)
Contribution of capital by parent	75,000		75,000
Ending Balance at Dec. 31, 2016	$ 1,931,696	$ 0	$ 1,446,223	$ 486,763	$ (1,290)
Ending Balance (in shares) at Dec. 31, 2016	100	100

STATEMENTS OF INCOME

STATEMENTS OF INCOME - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Income Statement [Abstract]
Operating revenues	$ 1,850,959	$ 1,787,218	$ 1,937,370
Operating expenses
Electric fuel and purchased power	1,034,950	1,001,083	1,192,176
Operating and maintenance expenses	269,471	289,856	277,217
Demand side management program expenses	16,028	13,365	12,350
Depreciation and amortization	162,429	150,913	135,632
Taxes (other than income taxes)	60,800	57,536	53,871
Total operating expenses	1,543,678	1,512,753	1,671,246
Operating income	307,281	274,465	266,124
Other income (expense), net	91	(6)	(59)
Allowance for funds used during construction — equity	9,981	7,378	12,118
Interest charges and financing costs
Interest charges — includes other financing costs of $3,055, $3,158 and $3,038, respectively	88,671	84,040	80,218
Public Utilities, Allowance For Funds Used During Construction, Capitalized Cost Of Debt	(5,589)	(4,491)	(7,089)
Total interest charges and financing costs	83,082	79,549	73,129
Income before income taxes	234,271	202,288	205,054
Income taxes	82,114	75,025	75,202
Net income	$ 152,157	$ 127,263	$ 129,852

STATEMENTS OF INCOME (Parenthet

STATEMENTS OF INCOME (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Interest charges and financing costs
Other financing costs	$ 3,055	$ 3,158	$ 3,038

BALANCE SHEETS

BALANCE SHEETS - USD ($) $ in Thousands		Dec. 31, 2016	Dec. 31, 2015
Current assets
Cash and cash equivalents		$ 844	$ 834
Accounts receivable, net		74,190	71,166
Accounts receivable from affiliates		949	1,079
Accrued unbilled revenues		119,418	103,781
Inventories		38,505	37,546
Regulatory assets		38,721	31,541
Derivative instruments		5,114	12,952
Prepaid taxes		21,779	35,666
Prepayments and other		7,855	20,520
Total current assets		307,375	315,085
Property, plant and equipment, net		4,695,819	4,348,823
Other assets
Regulatory assets		346,683	301,814
Derivative instruments		22,113	25,272
Other		7,477	3,449
Total other assets		376,273	330,535
Total assets		5,379,467	4,994,443
Current liabilities
Current portion of long-term debt		0	200,000
Short-term debt		50,000	15,000
Accounts payable		176,157	146,794
Accounts payable to affiliates		14,414	29,135
Regulatory liabilities	[1]	41,577	98,305
Taxes accrued		39,742	33,374
Accrued interest		19,162	17,781
Dividends payable		30,870	12,538
Derivative instruments		3,565	3,565
Other		29,703	35,654
Total current liabilities		405,190	592,146
Deferred credits and other liabilities
Deferred income taxes		989,137	860,744
Regulatory liabilities		233,454	229,584
Asset retirement obligations		28,663	27,233
Derivative instruments		23,513	27,078
Pension and employee benefit obligations		107,872	93,346
Other		24,084	17,841
Total deferred credits and other liabilities		1,406,723	1,255,826
Commitments and contingencies
Capitalization
Long-term debt		1,635,858	1,338,522
Common stock — 200 shares authorized of $1.00 par value; 100 shares outstanding at Dec. 31, 2016 and 2015, respectively		0	0
Additional paid in capital		1,446,223	1,371,223
Retained earnings		486,763	438,007
Accumulated other comprehensive loss		(1,290)	(1,281)
Total common stockholder’s equity		1,931,696	1,807,949
Total liabilities and equity		$ 5,379,467	$ 4,994,443
[1]	(b) Revenue subject to refund of $0 million and $3.9 million for 2016 and 2015, respectively, is included in other current liabilities.

BALANCE SHEETS (Parenthetical)

BALANCE SHEETS (Parenthetical) - $ / shares	Dec. 31, 2016	Dec. 31, 2015
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 INC

STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Comprehensive income:
Net income	$ 152,157	$ 127,263	$ 129,852
Other comprehensive (loss) income
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized Gain (Loss) Arising During Period, Net of Tax of $(84), $(260), and $0, respectively	(148)	(464)	0
Derivative instruments:
Reclassification of losses to net income, net of tax of $80, $97, and $96, respectively	139	172	172
Other comprehensive income	(9)	(292)	172
Comprehensive income	$ 152,148	$ 126,971	$ 130,024

STATEMENTS OF COMPREHENSIVE IN9

STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Derivative instruments:
Reclassification of losses to net income, tax	$ 80	$ 97	$ 96
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net Unamortized Gain (Loss) Arising During Period, Tax	$ (84)	$ (260)	$ 0

STATEMENTS OF CAPITALIZATION

STATEMENTS OF CAPITALIZATION - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Schedule of Capitalization, Long-term Debt [Line Items]
Unamortized discount (premium), net	$ 365	$ 605
Unamortized Debt Issuance Expense	(14,507)	(12,083)
Total long-term debt, including current maturities	1,635,858	1,538,522
Less: current maturities	0	200,000
Long-term debt	1,635,858	1,338,522
Common Stockholder's Equity
Common stock — 200 shares authorized of $1.00 par value; 100 shares outstanding at Dec. 31, 2016 and 2015, respectively	0	0
Additional paid in capital	1,446,223	1,371,223
Retained earnings	486,763	438,007
Accumulated other comprehensive loss	(1,290)	(1,281)
Total common stockholder’s equity	1,931,696	1,807,949
First Mortgage Bonds, Series due: | Series Due June 15, 2024
Schedule of Capitalization, Long-term Debt [Line Items]
Principal outstanding	350,000	350,000
First Mortgage Bonds, Series due: | Series Due Aug. 15, 2041
Schedule of Capitalization, Long-term Debt [Line Items]
Principal outstanding	400,000	400,000
First Mortgage Bonds, Series due: | Series Due Aug. 15, 2046
Schedule of Capitalization, Long-term Debt [Line Items]
Principal outstanding	300,000	0
Unsecured Senior Notes | Senior E Due Oct. 1, 2016
Schedule of Capitalization, Long-term Debt [Line Items]
Principal outstanding	0	200,000
Unsecured Senior Notes | Senior G Due Dec. 1, 2018
Schedule of Capitalization, Long-term Debt [Line Items]
Principal outstanding	250,000	250,000
Unsecured Senior Notes | Senior C and D Due Oct. 1, 2033
Schedule of Capitalization, Long-term Debt [Line Items]
Principal outstanding	100,000	100,000
Unsecured Senior Notes | Senior F Due Oct. 1, 2036
Schedule of Capitalization, Long-term Debt [Line Items]
Principal outstanding	$ 250,000	$ 250,000

STATEMENTS OF CAPITALIZATION (P

STATEMENTS OF CAPITALIZATION (Parenthetical) - $ / shares	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
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
First Mortgage Bonds, Series due: | Series Due June 15, 2024
Schedule of Capitalization, Long-term Debt [Line Items]
Maturity Date	Jun. 15, 2024	Jun. 15, 2024
Debt instrument, Interest Rate, Stated Percentage	3.30%	3.30%
First Mortgage Bonds, Series due: | Series Due Aug. 15, 2041
Schedule of Capitalization, Long-term Debt [Line Items]
Maturity Date	Aug. 15, 2041	Aug. 15, 2041
Debt instrument, Interest Rate, Stated Percentage	4.50%	4.50%
First Mortgage Bonds, Series due: | Series Due Aug. 15, 2046
Schedule of Capitalization, Long-term Debt [Line Items]
Maturity Date	Aug. 15, 2046	Aug. 15, 2046
Debt instrument, Interest Rate, Stated Percentage	3.40%	3.40%
Unsecured Senior Notes | Senior E Due Oct. 1, 2016
Schedule of Capitalization, Long-term Debt [Line Items]
Maturity Date	Oct. 1, 2016	Oct. 1, 2016
Debt instrument, Interest Rate, Stated Percentage	5.60%	5.60%
Unsecured Senior Notes | Senior G Due Dec. 1, 2018
Schedule of Capitalization, Long-term Debt [Line Items]
Maturity Date	Dec. 1, 2018	Dec. 1, 2018
Debt instrument, Interest Rate, Stated Percentage	8.75%	8.75%
Unsecured Senior Notes | Senior C and D Due Oct. 1, 2033
Schedule of Capitalization, Long-term Debt [Line Items]
Maturity Date	Oct. 1, 2033	Oct. 1, 2033
Debt instrument, Interest Rate, Stated Percentage	6.00%	6.00%
Unsecured Senior Notes | Senior F Due Oct. 1, 2036
Schedule of Capitalization, Long-term Debt [Line Items]
Maturity Date	Oct. 1, 2036	Oct. 1, 2036
Debt instrument, Interest Rate, Stated Percentage	6.00%	6.00%

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2016
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	Summary of Significant Accounting Policies Business and System of Accounts — SPS is 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 or potential disallowances, AROs, certain regulatory assets and liabilities, tax provisions, uncollectible amounts, environmental costs, unbilled revenues, jurisdictional fuel and energy cost allocations and actuarially determined benefit costs. The recorded estimates are revised when better information becomes available or when actual amounts can be determined. Those revisions can affect operating results. Regulatory Accounting — 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 or OCI, are deferred as regulatory liabilities based on the expectation the amounts will be returned to customers in future rates, or because the amounts were collected in rates prior to the costs being incurred. Estimates of recovering deferred costs and returning deferred credits are based on specific ratemaking decisions or precedent for each item. Regulatory assets and liabilities are amortized consistent with the treatment in the rate setting process. If restructuring or other changes in the regulatory environment occur, 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. SPS recognizes sales to both native load and other end use customers on a gross basis. 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. Other revenues and charges related to participating and transacting in RTOs are recorded on a net basis in 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. Certain rate rider mechanisms qualify as alternative revenue programs under generally accepted accounting principles. These mechanisms arise from costs imposed upon the utility by action of a regulator or legislative body related to an environmental, public safety, or other mandate. When certain criteria are met, revenue is recognized equal to the revenue requirement, including return on rate base items, for the qualified mechanisms. The mechanisms are revised periodically for differences between the total amount collected under the riders and the revenue recognized, which may increase or decrease the level of revenue collected from customers. 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 motor, air conditioner and lighting upgrades, as well as residential rebates for participation in air conditioner interruption and home weatherization. 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. Recorded revenues for incentive programs designed for recovery of lost margins and/or conservation performance incentives are limited to amounts expected to be collected within 24 months from 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 is tested for impairment when it is determined that the carrying value of the assets may not be recoverable. A loss is recognized in the current period if it becomes probable that part of a cost of a plant under construction or recently completed plant will be disallowed for recovery from customers and a reasonable estimate of the disallowance can be made. For investments in property, plant and equipment that are abandoned and not expected to go into service, incurred costs and related deferred tax amounts are compared to the discounted estimated future rate recovery, and a loss is recognized, if necessary. SPS records depreciation expense related to its plant using the straight-line method over the plant’s useful life. Actuarial life studies are performed and submitted to the state and federal commissions for review. Upon acceptance by the various commissions, the resulting lives and net salvage rates are used to calculate depreciation. Depreciation expense, expressed as a percentage of average depreciable property, was 2.7 , 2.6 and 2.5 percent for the years ended Dec. 31, 2016, 2015 and 2014, 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 accounts for AROs under accounting guidance that requires a liability for the fair value of an ARO to be recognized in the period in which it is incurred if it can be reasonably estimated, with the offsetting associated asset retirement costs capitalized as a long-lived asset. The liability is generally increased over time by applying the effective interest method of accretion, and the capitalized costs are depreciated over the useful life of the long-lived asset. Changes resulting from revisions to the timing or amount of expected asset retirement cash flows are recognized as an increase or a decrease in the ARO. SPS also recovers through rates certain future plant removal costs in addition to AROs. The accumulated removal costs for these obligations are reflected in the balance sheets as a regulatory liability. See Note 11 for further discussion of AROs. Income Taxes — 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 ratemaking purposes, the reversal of some temporary differences are accounted for as current income tax expense. Tax credits are recorded when earned unless there is a requirement to defer the benefit and amortize it over the book depreciable lives of the related property. The requirement to defer and amortize tax credits only applies to federal ITCs related to public utility property. Utility rate regulation also has resulted in the recognition of certain regulatory assets and liabilities related to income taxes, which are summarized in Note 12. 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 and interest rate activities, including forward contracts, futures, swaps and options. All derivative instruments not designated and qualifying for the normal purchases and normal sales exception, as defined by the accounting guidance for derivatives and hedging, are recorded on the 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. 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. 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. 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 NAVs. For interest rate derivatives, quoted prices based primarily on observable market interest rate curves are used as a primary input to establish fair value. For commodity derivatives, the most observable inputs available are generally used to determine the fair value of each contract. In the absence of a quoted price for an identical contract in an active market, 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 SO 2 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 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 be extended are treated as a capitalized cost of plant retirement. The depreciation expense levels recoverable in rates include a provision for removal expenses, which may include final remediation costs. Removal costs recovered in rates before the related costs are incurred are classified as a regulatory liability. See Note 11 for further discussion of environmental costs. Benefit Plans and Other Postretirement Benefits — 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. Reclassifications — Due to adoption of new accounting pronouncements, certain previously reported amounts have been reclassified to conform to the current year presentation. See Note 2 for further discussion of recently adopted accounting pronouncements. Subsequent Events — Management has evaluated the impact of events occurring after Dec. 31, 2016 up to the date of issuance of these financial statements. These statements contain all necessary adjustments and disclosures resulting from that evaluation.

Accounting Pronouncements

Accounting Pronouncements	12 Months Ended
	Dec. 31, 2016
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]
Accounting Pronouncements	Accounting Pronouncements Recently Issued Revenue Recognition — In May 2014, the FASB issued Revenue from Contracts with Customers, Topic 606 (ASU No. 2014-09) , which provides a new framework for the recognition of revenue. SPS expects its adoption will result in increased disclosures regarding revenue, cash flows and obligations related to arrangements with customers, as well as separate presentation of alternative revenue programs in the statements of income. SPS has not yet fully determined the impacts of adoption for several aspects of the standard, including a determination of whether receipts of non-refundable contributions in aid of construction should be recognized as revenues or may continue to be recorded as reductions to property, plant and equipment. Also, it is yet to be determined whether and how much an evaluation of the collectability of regulated electric revenues will impact the amounts of revenue recognized upon delivery. SPS currently expects to implement the standard on a modified retrospective basis, which requires application to contracts with customers effective Jan. 1, 2018, with the cumulative impact on contracts not yet completed as of Dec. 31, 2017 recognized as an adjustment to the opening balance of retained earnings. Classification and Measurement of Financial Instruments — In January 2016, the FASB issued Recognition and Measurement of Financial Assets and Financial Liabilities, Subtopic 825-10 (ASU No. 2016-01), which among other changes in accounting and disclosure requirements, replaces the cost method of accounting for non-marketable equity securities with a model for recognizing impairments and observable price changes, and also eliminates the available-for-sale classification for marketable equity securities. Under the new guidance, other than when the consolidation or equity method of accounting is utilized, changes in the fair value of equity securities are to be recognized in earnings. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, 2017. SPS is currently evaluating the impact of adopting ASU No. 2016-01 on its financial statements. Leases — In February 2016, the FASB issued Leases, Topic 842 (ASU No. 2016-02) , which, for lessees, requires balance sheet recognition of right-of-use assets and lease liabilities for all leases. Additionally, for leases that qualify as finance leases, the guidance requires expense recognition consisting of amortization of the right-of-use asset as well as interest on the related lease liability using the effective interest method. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, 2018, and early adoption is permitted. SPS is currently evaluating the impact of adopting ASU No. 2016-02 on its financial statements. Recently Adopted Consolidation — In February 2015, the FASB issued Amendments to the Consolidation Analysis, Topic 810 (ASU No. 2015-02) , which reduces the number of consolidation models and amends certain consolidation principles related to variable interest entities. SPS implemented the guidance on Jan. 1, 2016, and the implementation did not have a significant impact on its financial statements. Presentation of Debt Issuance Costs — In April 2015, the FASB issued Simplifying the Presentation of Debt Issuance Costs, Subtopic 835-30 (ASU No. 2015-03) , which requires the presentation of debt issuance costs on the balance sheet as a deduction from the carrying amount of the related debt, instead of presentation as an asset. SPS implemented the new guidance as required on Jan. 1, 2016, and as a result, $12.1 million of such deferred costs were retrospectively reclassified from other non-current assets to long-term debt on the balance sheet as of Dec. 31, 2015. Fair Value Measurement — In May 2015, the FASB issued Disclosures for Investments in Certain Entities that Calculate Net Asset Value per Share (or Its Equivalent), Topic 820 (ASU No. 2015-07), which eliminates the requirement to categorize fair value measurements using a NAV methodology in the fair value hierarchy. SPS implemented the guidance on Jan. 1, 2016, and the implementation did not have a material impact on its financial statements. For related disclosures, see Note 7 to the financial statements. Presentation of Deferred Taxes — In November 2015, the FASB issued Balance Sheet Classification of Deferred Taxes, Topic 740 (ASU No. 2015-17) , which eliminates the requirement to present deferred tax assets and liabilities as current and noncurrent on the balance sheet based on the classification of the related asset or liability, and instead requires classification of all deferred tax assets and liabilities as noncurrent. SPS early adopted the new guidance in the fourth quarter of 2016 and as a result $35.7 million of current deferred income taxes were retrospectively reclassified to long-term deferred income tax liabilities on the balance sheet as of Dec. 31, 2015. Stock Compensation — In March 2016, the FASB issued Improvements to Employee Share-Based Payment Accounting, Topic 718 (ASU No. 2016-09), which simplifies accounting and financial statement presentation for share-based payment transactions. The guidance requires that the difference between the tax deduction available upon settlement of share-based equity awards and the tax benefit accumulated over the vesting period be recognized as an adjustment to income tax expense. SPS adopted the guidance in 2016, and the implementation did not have a material impact on its financial statements.

Selected Balance Sheet Data

Selected Balance Sheet Data	12 Months Ended
	Dec. 31, 2016
Balance Sheet Related Disclosures [Abstract]
Selected Balance Sheet Data	Selected Balance Sheet Data (Thousands of Dollars) Dec. 31, 2016 Dec. 31, 2015 Accounts receivable, net Accounts receivable $ 80,569 $ 77,054 Less allowance for bad debts (6,379 ) (5,888 ) $ 74,190 $ 71,166 (Thousands of Dollars) Dec. 31, 2016 Dec. 31, 2015 Inventories Materials and supplies $ 25,453 $ 24,888 Fuel 13,052 12,658 $ 38,505 $ 37,546 (Thousands of Dollars) Dec. 31, 2016 Dec. 31, 2015 Property, plant and equipment, net Electric plant $ 6,362,189 $ 5,933,764 Construction work in progress 260,327 236,697 Total property, plant and equipment 6,622,516 6,170,461 Less accumulated depreciation (1,926,697 ) (1,821,638 ) $ 4,695,819 $ 4,348,823

Borrowings and Other Financing

Borrowings and Other Financing Instruments	12 Months Ended
	Dec. 31, 2016
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, 2016 Borrowing limit $ 100 Amount outstanding at period end — Average amount outstanding 20 Maximum amount outstanding 64 Weighted average interest rate, computed on a daily basis 0.83 % Weighted average interest rate at period end N/A (Amounts in Millions, Except Interest Rates) Twelve Months Ended Dec. 31, 2016 Twelve Months Ended Dec. 31, 2015 Twelve Months Ended Dec. 31, 2014 Borrowing limit $ 100 $ 100 $ 100 Amount outstanding at period end — — 16 Average amount outstanding 28 21 9 Maximum amount outstanding 100 100 100 Weighted average interest rate, computed on a daily basis 0.67 % 0.40 % 0.22 % Weighted average interest rate at end of period N/A N/A 0.45 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, 2016 Borrowing limit $ 400 Amount outstanding at period end 50 Average amount outstanding 19 Maximum amount outstanding 75 Weighted average interest rate, computed on a daily basis 0.74 % Weighted average interest rate at period end 0.95 (Amounts in Millions, Except Interest Rates) Twelve Months Ended Dec. 31, 2016 Twelve Months Ended Dec. 31, 2015 Twelve Months Ended Dec. 31, 2014 Borrowing limit $ 400 $ 400 $ 400 Amount outstanding at period end 50 15 37 Average amount outstanding 43 100 83 Maximum amount outstanding 140 246 241 Weighted average interest rate, computed on a daily basis 0.67 % 0.46 % 0.26 % Weighted average interest rate at end of period 0.95 0.60 0.47 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, 2016 and 2015, there were $5.0 million and $7.0 million of letters of credit outstanding, respectively, 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. Amended Credit Agreement — In June 2016, SPS entered into an amended five -year credit agreement with a syndicate of banks. The total borrowing limit under the amended credit agreement remained at $400 million . The amended credit agreement has substantially the same terms and conditions as the prior credit agreement with the following exceptions: • The maturity extended from October 2019 to June 2021 . • The Eurodollar borrowing margins on this line of credit was reduced to a range of 75 to 150 basis points per year, from a range of 87.5 to 175 basis points per year, based upon applicable long-term credit ratings. • The commitment fees, calculated on the unused portion of the line of credit, was reduced to a range of 6 to 22.5 basis points per year, from a range of 7.5 to 27.5 basis points per year, also based on applicable long-term credit ratings. SPS has the right to request an extension of the termination date for two additional one -year periods. The 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 47 percent and 46 percent at Dec. 31, 2016 and 2015, respectively. 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 . • SPS was in compliance with all financial covenants on its debt agreements as of Dec. 31, 2016 and 2015. At Dec. 31, 2016 , SPS had the following committed credit facility available (in millions): Credit Facility (a) Drawn (b) Available $ 400 $ 55.0 $ 345.0 (a) This credit facility matures in June 2021 . (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, 2016 and 2015 . 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 2016, SPS issued $300 million of 3.4 percent first mortgage bonds due Aug. 15, 2046 . In 2015, SPS issued $200 million of 3.3 percent first mortgage bonds due June 15, 2024 . During the next five years, SPS has long-term debt maturities of $250 million due in 2018. Deferred Financing Costs — Deferred financing costs of approximately $14.5 million and $12.1 million , net of amortization, are presented as a deduction from the carrying amount of long-term debt at Dec. 31, 2016 and 2015 , respectively. 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, 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 54.1 percent at Dec. 31, 2016 and $487 million in retained earnings was not restricted.

Preferred Stock

Preferred Stock	12 Months Ended
	Dec. 31, 2016
Equity [Abstract]
Preferred Stock	Preferred Stock SPS has authorized the issuance of preferred stock. Preferred Par Value Preferred 10,000,000 $ 1.00 None

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2016
Income Tax Disclosure [Abstract]
Income Taxes	Income Taxes Consolidated Appropriations Act, 2016 — In December 2015, the Consolidated Appropriations Act, 2016 (Act) was signed into law. The Act provides for the following: • Immediate expensing, or “bonus depreciation,” of 50 percent for property placed in service in 2015, 2016, and 2017; 40 percent for property placed in service in 2018; and 30 percent for property placed in service in 2019. Additionally, some longer production period property placed in service in 2020 will be eligible for bonus depreciation; • PTCs at 100 percent of the credit rate ( $0.023 per KWh) for wind energy projects that begin construction by the end of 2016; 80 percent of the credit rate for projects that begin construction in 2017; 60 percent of the credit rate for projects that begin construction in 2018; and 40 percent of the credit rate for projects that begin construction in 2019. The wind energy PTC was not extended for projects that begin construction after 2019; • ITCs at 30 percent for commercial solar projects that begin construction by the end of 2019; 26 percent for projects that begin construction in 2020; 22 percent for projects that begin construction in 2021; and 10 percent for projects thereafter; • R&E credit was permanently extended; and • Delay of two years (until 2020) of the excise tax on certain employer-provided health insurance plans. The accounting related to the Act was recorded beginning in the fourth quarter of 2015 because a change in tax law is accounted for beginning in the period of enactment. Tax Increase Prevention Act of 2014 — In 2014, the Tax Increase Prevention Act (TIPA) was signed into law. The TIPA provides for the following: • The R&E credit was extended for 2014; • PTCs were extended for projects that began construction before the end of 2014 with certain projects qualifying into future years; and • 50 percent bonus depreciation was extended one year through 2014. Additionally, some longer production period property placed in service in 2015 is also eligible for 50 percent bonus depreciation. The accounting related to the TIPA was recorded beginning in the fourth quarter of 2014 because a change in tax law is accounted for in the period of enactment. Federal Audit — SPS is a member of the Xcel Energy affiliated group that files a consolidated federal income tax return. In 2012, the IRS commenced an examination of tax years 2010 and 2011 , including a 2009 carryback claim. As of Dec. 31, 2016, the IRS had proposed an adjustment to the federal tax loss carryback claims that would result in $14 million of income tax expense for the 2009 through 2011 claims, and the 2013 through 2015 claims. In the fourth quarter of 2015, the IRS forwarded the issue to the Office of Appeals (Appeals). In 2016 the IRS audit team and Xcel Energy presented their cases to Appeals; however, the outcome and timing of a resolution is uncertain. The statute of limitations applicable to Xcel Energy’s 2009 through 2011 federal income tax returns, following extensions, expires in December 2017. Xcel Energy has recognized its best estimate of income tax expense that will result from a final resolution of the IRS’ proposed adjustment of the carryback claims. SPS is not expected to accrue any income tax expense related to this adjustment. In the third quarter of 2015, the IRS commenced an examination of tax years 2012 and 2013 . As of Dec. 31, 2016, the IRS had not proposed any material adjustments to tax years 2012 and 2013. Subsequent to year-end, the IRS proposed an adjustment to tax years 2012 through 2013 that may impact Xcel Energy’s NOL and tax credit carryforwards and ETR. However, Xcel Energy is continuing to evaluate the IRS’ proposal and the outcome and timing of a resolution is uncertain. State Audits — SPS is a member of the Xcel Energy affiliated group that files consolidated state income tax returns. As of Dec. 31, 2016, SPS’ earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations is 2009 . In February 2016, Texas began an audit of years 2009 and 2010 . As of Dec. 31, 2016, Texas had not proposed any adjustments, and there were no other state income tax audits in progress. Unrecognized Tax Benefits — The unrecognized tax benefit balance includes permanent tax positions, which if recognized would affect the annual ETR. In addition, the unrecognized tax benefit balance includes temporary tax positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. A change in the period of deductibility would not affect the ETR but would accelerate the payment of cash to the taxing authority to an earlier period. A reconciliation of the amount of unrecognized tax benefit is as follows: (Millions of Dollars) Dec. 31, 2016 Dec. 31, 2015 Unrecognized tax benefit — Permanent tax positions $ 4.5 $ 2.6 Unrecognized tax benefit — Temporary tax positions 24.2 22.1 Total unrecognized tax benefit $ 28.7 $ 24.7 A reconciliation of the beginning and ending amount of unrecognized tax benefit is as follows: (Millions of Dollars) 2016 2015 2014 Balance at Jan. 1 $ 24.7 $ 13.2 $ 4.1 Additions based on tax positions related to the current year 1.4 4.2 8.6 Reductions based on tax positions related to the current year — (0.6 ) — Additions for tax positions of prior years 3.9 9.0 2.3 Reductions for tax positions of prior years (1.3 ) (1.1 ) (0.3 ) Settlements with taxing authorities — — (0.2 ) Lapse of applicable statutes of limitations — — (1.3 ) Balance at Dec. 31 $ 28.7 $ 24.7 $ 13.2 The unrecognized tax benefit amounts were reduced by the tax benefits associated with NOL and tax credit carryforwards. The amounts of tax benefits associated with NOL and tax credit carryforwards are as follows: (Millions of Dollars) Dec. 31, 2016 Dec. 31, 2015 NOL and tax credit carryforwards $ (5.9 ) $ (5.0 ) It is reasonably possible that SPS’ amount of unrecognized tax benefits could significantly change in the next 12 months as the IRS Appeals and audit progress, the Texas audit progresses, and other state audits resume. As the IRS Appeals, IRS audit, and Texas audit progress, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $10 million . The payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryforwards. A reconciliation of the beginning and ending amount of the payable for interest related to unrecognized tax benefits are as follows: (Millions of Dollars) 2016 2015 2014 Payable for interest related to unrecognized tax benefits at Jan. 1 $ — $ (0.1 ) $ — Interest (expense) income related to unrecognized tax benefits (0.9 ) 0.1 (0.1 ) Payable for interest related to unrecognized tax benefits at Dec. 31 $ (0.9 ) $ — $ (0.1 ) No amounts were accrued for penalties related to unrecognized tax benefits as of Dec. 31, 2016, 2015, or 2014. Other Income Tax Matters — NOL amounts represent the amount of the tax loss that is carried forward and tax credits represent the deferred tax asset. NOL and tax credit carryforwards as of Dec. 31 were as follows: (Millions of Dollars) 2016 2015 Federal NOL carryforward $ 275 $ 306 Federal tax credit carryforwards 4 3 State NOL carryforwards 60 79 Valuation allowances for state NOL carryforwards — (11 ) The federal carryforward periods expire between 2021 and 2036 . The state carryforward periods expire between 2017 and 2035 . Total income tax expense from operations differs from the amount computed by applying the statutory federal income tax rate to income before income tax expense. The following reconciles such differences for the years ending Dec. 31: 2016 2015 2014 Federal statutory rate 35.0 % 35.0 % 35.0 % Increases (decreases) in tax from: State income taxes, net of federal income tax benefit 1.5 2.6 3.4 Change in unrecognized tax benefits 0.8 0.5 0.2 Regulatory differences — utility plant items (1.0 ) (0.8 ) (1.6 ) Tax credits recognized, net of federal income tax expense (0.5 ) (0.3 ) (0.4 ) Other, net (0.7 ) 0.1 0.1 Effective income tax rate 35.1 % 37.1 % 36.7 % The components of income tax expense for the years ending Dec. 31 were: (Thousands of Dollars) 2016 2015 2014 Current federal tax benefit $ (40,853 ) $ (1,327 ) $ (57,201 ) Current state tax (benefit) expense (2,929 ) 2,448 2,512 Current change in unrecognized tax expense 3,126 11,281 6,715 Deferred federal tax expense 116,404 67,640 121,882 Deferred state tax expense 7,757 5,399 8,025 Deferred change in unrecognized tax benefit (1,178 ) (10,203 ) (6,390 ) Deferred investment tax credits (213 ) (213 ) (341 ) Total income tax expense $ 82,114 $ 75,025 $ 75,202 The components of deferred income tax expense for the years ending Dec. 31 were: (Thousands of Dollars) 2016 2015 2014 Deferred tax expense excluding items below $ 128,393 $ 63,453 $ 124,875 Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities (5,416 ) (780 ) (1,262 ) Tax benefit (expense) allocated to other comprehensive income and other 6 163 (96 ) Deferred tax expense $ 122,983 $ 62,836 $ 123,517 The components of the net deferred tax liability at Dec. 31 were as follows: (Thousands of Dollars) 2016 2015 Deferred tax liabilities: Differences between book and tax bases of property $ 1,034,675 $ 945,142 Employee benefits 42,239 50,097 Other 35,975 18,260 Total deferred tax liabilities $ 1,112,889 $ 1,013,499 Deferred tax assets: NOL carryforward $ 100,179 $ 112,060 Deferred fuel costs 10,226 23,127 Regulatory liabilities 3,380 10,480 Other 9,967 7,088 Total deferred tax assets $ 123,752 $ 152,755 Net deferred tax liability $ 989,137 $ 860,744

Benefit Plans and Other Postret

Benefit Plans and Other Postretirement Benefits	12 Months Ended
	Dec. 31, 2016
Compensation and Retirement Disclosure [Abstract]
Benefit Plans and Other Postretirement Benefits	Benefit Plans and Other Postretirement Benefits Consistent with the process for rate recovery of pension and postretirement benefits for its employees, 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 67 percent of employees that receive benefits are represented by several local labor unions under several collective-bargaining agreements. At Dec. 31, 2016 , SPS had 833 bargaining employees covered under a collective-bargaining agreement, which expired in October 2014. While collective bargaining is ongoing, the terms and conditions of the expired agreement are automatically extended. The plans invest in various instruments which are disclosed under the accounting guidance for fair value measurements which establishes a hierarchical framework for disclosing the observability of the inputs utilized in measuring fair value. The three levels in the hierarchy and examples of each level are as follows: Level 1 — Quoted prices are available in active markets for identical assets as of the reporting date. The types of assets included in Level 1 are highly liquid and actively traded instruments with quoted prices. Level 2 — Pricing inputs are other than quoted prices in active markets, but are either directly or indirectly observable as of the reporting date. The types of assets included in Level 2 are typically either comparable to actively traded securities or contracts, or priced with models using highly observable inputs. Level 3 — Significant inputs to pricing have little or no observability as of the reporting date. The types of assets included in Level 3 are those with inputs requiring significant management judgment or estimation. Specific valuation methods include the following: Cash equivalents — The fair values of cash equivalents are generally based on cost plus accrued interest; money market funds are measured using quoted NAVs. Insurance contracts — Insurance contract fair values take into consideration the value of the investments in separate accounts of the insurer, which are priced based on observable inputs. Investments in commingled funds, equity securities and other funds — Equity securities are valued using quoted prices in active markets. The fair values for commingled funds are measured using NAVs, which take into consideration the value of underlying fund investments, as well as the other accrued assets and liabilities of a fund, in order to determine a per share market value. The investments in commingled funds may be redeemed for NAV with proper notice. Proper notice varies by fund and can range from daily with a few days’ notice to annually with 90 days ’ notice. Private equity investments require approval of the fund for any unscheduled redemption, and such redemptions may be approved or denied by the fund at its sole discretion. Depending on the fund, unscheduled distributions from real estate investments may require approval of the fund or may be redeemed with proper notice, which is typically quarterly with 45 - 90 days ’ notice; however, withdrawals from real estate investments may be delayed or discounted as a result of fund illiquidity. Investments in debt securities — Fair values for debt securities are determined by a third party pricing service using recent trades and observable spreads from benchmark interest rates for similar securities. Derivative Instruments — Fair values for foreign currency derivatives are determined using pricing models based on the prevailing forward exchange rate of the underlying currencies. The fair values of interest rate derivatives are based on broker quotes that utilize current market interest rate forecasts. Pension Benefits Xcel Energy, which includes SPS, has several noncontributory, defined benefit pension plans that cover almost all employees. Generally, benefits are based on a combination of years of service, the employee’s average pay and, in some cases, social security benefits. Xcel Energy Inc.’s and 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, with distributions attributable to SPS funded by SPS’ operating cash flows. The total obligations of the SERP and nonqualified plan as of Dec. 31, 2016 and 2015 were $43.5 million and $41.8 million , respectively, of which $2.5 million and $2.6 million were attributable to SPS. In 2016 and 2015 , Xcel Energy recognized net benefit cost for financial reporting for the SERP and nonqualified plans of $7.9 million and $9.5 million , respectively, of which $0.2 million and $0.3 million were attributable to SPS. In 2016, Xcel Energy established rabbi trusts to provide partial funding for future distributions of the SERP and its deferred compensation plan. Rabbi trust funding of deferred compensation plan distributions attributable to SPS will be supplemented by SPS operating cash flows as determined necessary. The amount of rabbi trust funding attributable to SPS is immaterial. Also in 2016, Xcel Energy amended the deferred compensation plan to provide eligible participants the ability to diversify deferred settlements of equity awards, other than time-based equity awards, into various fund options. Xcel Energy Inc. and 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. Xcel Energy Inc. and SPS continually review the pension assumptions. The pension cost determination assumes a forecasted mix of investment types over the long-term. • Investment returns in 2016 were below the assumed level of 6.78 percent ; • Investment returns in 2015 were below the assumed level of 7.22 percent ; • Investment returns in 2014 were above the assumed level of 6.90 percent ; and • In 2017, SPS’ expected investment-return assumption is 6.80 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 at Dec. 31 for the upcoming year: 2016 2015 Domestic and international equity securities 36 % 36 % Long-duration fixed income and interest rate swap securities 31 31 Short-to-intermediate fixed income securities 15 12 Alternative investments 16 19 Cash 2 2 Total 100 % 100 % The ongoing investment strategy is based on plan-specific investment recommendations that seek to minimize potential investment and interest rate risk as a plan’s funded status increases over time. The investment recommendations result in a greater percentage of long-duration fixed income securities being allocated to specific plans having relatively higher funded status ratios and a greater percentage of growth assets being allocated to plans having relatively lower funded status ratios. The aggregate projected asset allocation presented in the table above for the master pension trust results from the plan-specific strategies. Pension Plan Assets The following tables present, for each of the fair value hierarchy levels, SPS’ pension plan assets that are measured at fair value as of Dec. 31, 2016 and 2015 : Dec. 31, 2016 (Thousands of Dollars) Level 1 Level 2 Level 3 Investments Measured at NAV (a) Total Cash equivalents $ 29,237 $ — $ — $ — $ 29,237 Commingled funds: U.S. equity funds — — — 62,899 62,899 Non U.S. equity funds — — — 46,403 46,403 U.S. corporate bond funds — — — 41,226 41,226 Emerging market equity funds — — — 24,637 24,637 Emerging market debt funds — — — 20,399 20,399 Commodity funds — — — 2,876 2,876 Private equity investments — — — 12,098 12,098 Real estate — — — 23,232 23,232 Other commingled funds — — — 28,247 28,247 Debt securities: Government securities — 38,105 — — 38,105 U.S. corporate bonds — 36,293 — — 36,293 Non U.S. corporate bonds — 5,818 — — 5,818 Mortgage-backed securities — 821 — — 821 Asset-backed securities — 389 — — 389 Equity securities: U.S. equities 10,477 — — — 10,477 Other — (2,762 ) — — (2,762 ) Total $ 39,714 $ 78,664 $ — $ 262,017 $ 380,395 (a) Based on the requirements of ASU No. 2015-07, investments measured at fair value using a NAV methodology have not been classified in the fair value hierarchy. See Note 2 for further information on the adoption of ASU No. 2015-07. Dec. 31, 2015 (Thousands of Dollars) Level 1 Level 2 Level 3 Investments Measured at NAV (a) Total Cash equivalents $ 22,999 $ — $ — $ — $ 22,999 Derivatives — 553 — — 553 Commingled funds: U.S. equity funds — — — 55,533 55,533 Non U.S. equity funds — — — 53,449 53,449 U.S. corporate bond funds — — — 32,020 32,020 Emerging market equity funds — — — 23,891 23,891 Emerging market debt funds — — — 23,169 23,169 Commodity funds — — — 7,884 7,884 Private equity investments — — — 19,114 19,114 Real estate — — — 27,690 27,690 Other commingled funds — — — 29,793 29,793 Debt securities: Government securities — 37,495 — — 37,495 U.S. corporate bonds — 28,826 — — 28,826 Non U.S. corporate bonds — 4,626 — — 4,626 Asset-backed securities — 323 — — 323 Equity securities: U.S. equities 13,492 — — — 13,492 Other — (1,944 ) — — (1,944 ) Total $ 36,491 $ 69,879 $ — $ 272,543 $ 378,913 (a) Based on the requirements of ASU No. 2015-07, investments measured at fair value using a NAV methodology have not been classified in the fair value hierarchy. See Note 2 for further information on the adoption of ASU No. 2015-07. There were no assets transferred in or out of Level 3 for the years ended Dec. 31, 2016, 2015 or 2014. Benefit Obligations — A comparison of the actuarially computed pension benefit obligation and plan assets for SPS is presented in the following table: (Thousands of Dollars) 2016 2015 Accumulated Benefit Obligation at Dec. 31 $ 453,317 $ 429,726 Change in Projected Benefit Obligation: Obligation at Jan. 1 $ 467,394 $ 500,690 Service cost 9,761 11,006 Interest cost 21,259 20,184 Actuarial loss (gain) 25,053 (35,154 ) Transfer to other plan (3,305 ) (2,843 ) Benefit payments (36,561 ) (26,489 ) Obligation at Dec. 31 $ 483,601 $ 467,394 (Thousands of Dollars) 2016 2015 Change in Fair Value of Plan Assets: Fair value of plan assets at Jan. 1 $ 378,913 $ 402,269 Actual return (loss) on plan assets 23,306 (6,013 ) Employer contributions 18,088 11,651 Transfer to other plan (3,351 ) (2,505 ) Benefit payments (36,561 ) (26,489 ) Fair value of plan assets at Dec. 31 $ 380,395 $ 378,913 (Thousands of Dollars) 2016 2015 Funded Status of Plans at Dec. 31: Funded status (a) $ (103,206 ) $ (88,481 ) (a) Amounts are recognized in noncurrent liabilities on SPS’ balance sheets. (Thousands of Dollars) 2016 2015 Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost: Net loss $ 247,381 $ 236,107 (Thousands of Dollars) 2016 2015 Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost Have Been Recorded as Follows Based Upon Expected Recovery in Rates: Current regulatory assets $ 13,524 $ 13,690 Noncurrent regulatory assets 233,857 222,417 Total $ 247,381 $ 236,107 Measurement date Dec. 31, 2016 Dec. 31, 2015 2016 2015 Significant Assumptions Used to Measure Benefit Obligations: Discount rate for year-end valuation 4.13 % 4.66 % Expected average long-term increase in compensation level 3.75 4.00 Mortality table RP-2014 RP-2014 Mortality — In 2014, the Society of Actuaries published a new mortality table (RP-2014) and projection scale (MP-2014) that increased the overall life expectancy of males and females. On Dec. 31, 2014 SPS adopted the RP-2014 table, with modifications, based on its population and specific experience and a modified MP-2014 projection scale. During 2016, a new projection table was released (MP-2016). In 2016, SPS adopted a modified version of the MP-2016 table and will continue to utilize the RP-2014 base table, modified for company experience. Cash Flows — Cash funding requirements can be impacted by changes to actuarial assumptions, actual asset levels and other calculations prescribed by the funding requirements of income tax and other pension-related regulations. Required contributions were made in 2014 through 2017 to meet minimum funding requirements. Total voluntary and required pension funding contributions across all four of Xcel Energy’s pension plans were as follows: • $150.0 million in January 2017, of which $23.0 million was attributable to SPS; • $125.2 million in 2016, of which $18.1 million was attributable to SPS • $90.1 million in 2015, of which $11.7 million was attributable to SPS; and • $130.6 million in 2014, of which $4.9 million was attributable to SPS. For future years, Xcel Energy and SPS anticipate contributions will be made as necessary. Plan Amendments — In 2016 and 2015, there were no plan amendments made which affected the benefit obligation. Benefit Costs — The components of SPS’ net periodic pension cost were: (Thousands of Dollars) 2016 2015 2014 Service cost $ 9,761 $ 11,006 $ 9,184 Interest cost 21,259 20,184 20,444 Expected return on plan assets (27,602 ) (28,610 ) (26,179 ) Amortization of prior service cost — 39 54 Amortization of net loss 11,986 15,087 13,326 Net periodic pension cost 15,404 17,706 16,829 Credits not recognized due to effects of regulation 2,042 2,597 3,170 Net benefit cost recognized for financial reporting $ 17,446 $ 20,303 $ 19,999 2016 2015 2014 Significant Assumptions Used to Measure Costs: Discount rate 4.66 % 4.11 % 4.75 % Expected average long-term increase in compensation level 4.00 3.75 3.75 Expected average long-term rate of return on assets 6.78 7.22 6.90 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 $4.4 million , $4.8 million and $4.1 million in 2016 , 2015 and 2014 , respectively. Pension costs include an expected return impact for the current year that may differ from actual investment performance in the plan. The return assumption used for 2017 pension cost calculations is 6.80 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 $2.8 million in 2016 , and $2.6 million in 2015 and 2014 . 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 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. 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. These assets are invested in a manner consistent with the investment strategy for the pension plan. The following table presents the target postretirement asset allocations for Xcel Energy Inc. and SPS at Dec. 31 for the upcoming year: 2016 2015 Domestic and international equity securities 25 % 25 % Short-to-intermediate fixed income securities 57 57 Alternative investments 13 13 Cash 5 5 Total 100 % 100 % Xcel Energy Inc. and 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. Assumptions and target allocations are determined at the master trust level. The investment mix at each of Xcel Energy Inc.’s utility subsidiaries may vary from the investment mix of the total asset portfolio. The assets are invested in a portfolio according to Xcel Energy Inc.’s and 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’ proportionate allocation of the total postretirement benefit plan assets that are measured at fair value as of Dec. 31, 2016 and 2015 : Dec. 31, 2016 (Thousands of Dollars) Level 1 Level 2 Level 3 Investments Measured at NAV (a) Total Cash equivalents $ 1,966 $ — $ — $ — $ 1,966 Insurance contracts — 4,519 — — 4,519 Commingled funds: U.S. equity funds — — — 5,208 5,208 U.S fixed income funds — — — 2,593 2,593 Emerging market debt funds — — — 2,911 2,911 Other commingled funds — — — 5,258 5,258 Debt securities: Government securities — 3,611 — — 3,611 U.S. corporate bonds — 5,962 — — 5,962 Non U.S. corporate bonds — 1,653 — — 1,653 Asset-backed securities — 1,810 — — 1,810 Mortgage-backed securities — 2,748 — — 2,748 Equity securities: Non U.S. equities 3,919 — — — 3,919 Other — 139 — — 139 Total $ 5,885 $ 20,442 $ — $ 15,970 $ 42,297 (a) Based on the requirements of ASU No. 2015-07, investments measured at fair value using a NAV methodology have not been classified in the fair value hierarchy. See Note 2 for further information on the adoption of ASU No. 2015-07. Dec. 31, 2015 (Thousands of Dollars) Level 1 Level 2 Level 3 Investments Measured at NAV (a) Total Cash equivalents $ 1,873 $ — $ — $ — $ 1,873 Insurance contracts — 4,501 — — 4,501 Commingled funds: U.S. equity funds — — — 3,643 3,643 Non U.S. equity funds — — — 3,204 3,204 U.S fixed income funds — — — 2,311 2,311 Emerging market equity funds — — — 1,058 1,058 Emerging market debt funds — — — 3,401 3,401 Other commingled funds — — — 5,910 5,910 Debt securities: Government securities — 3,742 — — 3,742 U.S. corporate bonds — 5,710 — — 5,710 Non U.S. corporate bonds — 1,239 — — 1,239 Asset-backed securities — 2,736 — — 2,736 Mortgage-backed securities — 3,396 — — 3,396 Other — (40 ) — — (40 ) Total $ 1,873 $ 21,284 $ — $ 19,527 $ 42,684 (a) Based on the requirements of ASU No. 2015-07, investments measured at fair value using a NAV methodology have not been classified in the fair value hierarchy. See Note 2 for further information on the adoption of ASU No. 2015-07. There were no assets transferred in or out of Level 3 for the years ended Dec. 31, 2016 , 2015 or 2014 . Benefit Obligations — A comparison of the actuarially computed benefit obligation and plan assets for SPS is presented in the following table: (Thousands of Dollars) 2016 2015 Change in Projected Benefit Obligation: Obligation at Jan. 1 $ 40,864 $ 44,342 Service cost 775 954 Interest cost 1,821 1,745 Medicare subsidy reimbursements 31 45 Plan participants’ contributions 653 687 Actuarial loss (gain) 1,293 (3,793 ) Benefit payments (3,577 ) (3,116 ) Obligation at Dec. 31 $ 41,860 $ 40,864 (Thousands of Dollars) 2016 2015 Change in Fair Value of Plan Assets: Fair value of plan assets at Jan. 1 $ 42,684 $ 45,356 Actual return (loss) on plan assets 1,978 (421 ) Plan participants’ contributions 653 687 Employer contributions 559 178 Benefit payments (3,577 ) (3,116 ) Fair value of plan assets at Dec. 31 $ 42,297 $ 42,684 (Thousands of Dollars) 2016 2015 Funded Status of Plans at Dec. 31: Funded status (a) $ 437 $ 1,820 (a) Amounts are recognized in noncurrent assets on SPS’ balance sheet as of Dec. 31, 2016 and 2015. (Thousands of Dollars) 2016 2015 Amounts Not Yet Recognized as Components of Net Periodic Benefit Credit: Net gain $ (12,595 ) $ (14,870 ) Prior service credit (2,630 ) (3,031 ) Total $ (15,225 ) $ (17,901 ) (Thousands of Dollars) 2016 2015 Amounts Not Yet Recognized as Components of Net Periodic Benefit Credit Have Been Recorded as Follows Based Upon Expected Recovery in Rates: Current regulatory liabilities $ (1,004 ) $ (985 ) Noncurrent regulatory liabilities (14,221 ) (16,916 ) Total $ (15,225 ) $ (17,901 ) Measurement date Dec. 31, 2016 Dec. 31, 2015 2016 2015 Significant Assumptions Used to Measure Benefit Obligations: Discount rate for year-end valuation 4.13 % 4.65 % Mortality table RP 2014 RP 2014 Health care costs trend rate — initial 5.50 % 6.00 % Effective Jan. 1, 2017, the initial medical trend rate was decreased from 6.0 percent to 5.5 percent . The ultimate trend assumption remained at 4.5 percent . The period until the ultimate rate is reached is two years . Xcel Energy Inc. and 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 $ 3,979 $ (3,389 ) Service and interest components 273 (231 ) Cash Flows — The postretirement health care plans have no funding requirements under income tax and other retirement-related regulations other than fulfilling benefit payment obligations, when claims are presented and approved under the plans. Additional cash funding requirements are prescribed by certain state and federal rate regulatory authorities. Xcel Energy, which includes SPS, contributed $17.9 million , $18.3 million and $17.1 million during 2016 , 2015 and 2014 , respectively, of which $0.6 million , $0.2 million and $0.2 million were attributable to SPS. Xcel Energy expects to contribute approximately $11.8 million during 2017 , of which amounts attributable to SPS will be zero . Plan Amendments — In 2016 and 2015, there were no plan amendments made which affected the benefit obligation. Benefit Costs — The components of SPS’ net periodic postretirement benefit costs were: (Thousands of Dollars) 2016 2015 2014 Service cost $ 775 $ 954 $ 1,246 Interest cost 1,821 1,745 2,572 Expected return on plan assets (2,377 ) (2,540 ) (3,247 ) Amortization of prior service credit (401 ) (401 ) (401 ) Amortization of net gain (583 ) (639 ) (321 ) Net periodic postretirement benefit credit $ (765 ) $ (881 ) $ (151 ) 2016 2015 2014 Significant Assumptions Used to Measure Costs: Discount rate 4.65 % 4.08 % 4.82 % Expected average long-term rate of return on assets 5.80 5.80 7.20 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 2017 $ 28,596 $ 3,420 $ 24 $ 3,396 2018 28,086 3,203 26 3,177 2019 28,545 3,008 24 2,984 2020 29,567 3,015 25 2,990 2021 29,716 3,096 26 3,070 2022-2026 156,673 14,135 148 13,987

Other Income, Net

Other Income, Net	12 Months Ended
	Dec. 31, 2016
Other Income and Expenses [Abstract]
Other Income, Net	Other Income (Expense), Net Other income (expense), net for the years ended Dec. 31 consisted of the following: (Thousands of Dollars) 2016 2015 2014 Interest income $ 129 $ 129 $ 246 Other nonoperating income 5 11 183 Insurance policy expense (43 ) (40 ) (488 ) Other nonoperating expense — (106 ) — Other income (expense), net $ 91 $ (6 ) $ (59 )

Fair Value of Financial Assets

Fair Value of Financial Assets and Liabilities	12 Months Ended
	Dec. 31, 2016
Fair Value Disclosures [Abstract]
Fair Value of Financial Assets and Liabilities	Fair Value of Financial Assets and Liabilities Fair Value Measurements The accounting guidance for fair value measurements and disclosures provides a single definition of fair value and requires certain disclosures about assets and liabilities measured at fair value. A hierarchical framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value is established by this guidance. The three levels in the hierarchy are as follows: Level 1 — Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. The types of assets and liabilities included in Level 1 are highly liquid and actively traded instruments with quoted prices. Level 2 — Pricing inputs are other than quoted prices in active markets, but are either directly or indirectly observable as of the reporting date. The types of assets and liabilities included in Level 2 are typically either comparable to actively traded securities or contracts, or priced with models using highly observable inputs. Level 3 — Significant inputs to pricing have little or no observability as of the reporting date. The types of assets and liabilities included in Level 3 are those valued with models requiring significant management judgment or estimation. Specific valuation methods include the following: Cash equivalents — The fair values of cash equivalents are generally based on cost plus accrued interest; money market funds are measured using quoted NAVs. Interest rate derivatives — The fair values of interest rate derivatives are based on broker quotes that utilize current market interest rate forecasts. Commodity derivatives — The methods used to measure the fair value of commodity derivative forwards and options utilize forward prices and volatilities, as well as pricing adjustments for specific delivery locations, and are generally assigned a Level 2. When contractual settlements extend to periods beyond those readily observable on active exchanges or quoted by brokers, the significance of the use of less observable forecasts of long-term forward prices and volatilities on a valuation is evaluated, and may result in Level 3 classification. Electric commodity derivatives held by SPS include transmission congestion instruments, generally referred to as FTRs, purchased from SPP. 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, 2016, accumulated other comprehensive losses related to interest rate derivatives included $0.1 million of net losses expected to be reclassified into earnings during the next 12 months as the related hedged interest rate transactions impact earnings, including forecasted amounts for unsettled hedges, as applicable. 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, including derivatives. 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. This could include the purchase or sale of energy or energy-related products and FTRs. The following table details the gross notional amounts of commodity FTRs at Dec. 31, 2016 and 2015: (Amounts in Thousands) (a) Dec. 31, 2016 Dec. 31, 2015 MWh of electricity 2,685 6,192 (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 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, 2016, seven of the eight most significant counterparties, comprising $50.0 million or 56 percent of this credit exposure, were not rated by external rating agencies, but based on SPS’ internal analysis, had credit quality consistent with investment grade. One of these significant counterparties, comprising $1.9 million or 2 percent of this credit exposure, had credit quality less than investment grade, based on SPS’ internal analysis. Seven 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) 2016 2015 2014 Accumulated other comprehensive loss related to cash flow hedges at Jan. 1 $ (817 ) $ (989 ) $ (1,161 ) After-tax net realized losses on derivative transactions reclassified into earnings 139 172 172 Accumulated other comprehensive loss related to cash flow hedges at Dec. 31 $ (678 ) $ (817 ) $ (989 ) Pre-tax losses related to interest rate derivatives reclassified from accumulated other comprehensive loss into earnings were $0.2 million for the year ended Dec. 31, 2016 and $0.3 million each of the years ended Dec. 31, 2015 and 2014. Changes in the fair value of FTRs resulting in pre-tax net gains of $3.0 million for the year ended Dec. 31, 2016 and pre-tax net losses of $3.1 million and $3.9 million for the years ended Dec. 31, 2015 and 2014, respectively, 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. FTR settlement gains of $2.1 million were recognized for the year ended Dec. 31, 2016 and FTR settlement losses of $1.6 million and $8.2 million were recognized for the years ended Dec. 31, 2015 and Dec. 31, 2014, recorded to electric fuel and purchased power. These derivative settlement gains and losses are shared with electric customers through fuel and purchased energy cost-recovery mechanisms, and reclassified out of income as regulatory assets or liabilities, as appropriate. SPS had no derivative instruments designated as fair value hedges during the years ended Dec. 31, 2016, 2015 and 2014. Therefore, no gains or losses from fair value hedges or related hedged transactions were recognized for these periods. Recurring Fair Value Measurements — The following table presents for each of the fair value hierarchy levels, SPS’ derivative assets and liabilities measured at fair value on a recurring basis at Dec. 31, 2016: Dec. 31, 2016 Fair Value Fair Value Total Counterparty Netting (b) (Thousands of Dollars) Level 1 Level 2 Level 3 Total Current derivative assets Other derivative instruments: Electric commodity $ — $ — $ 3,254 $ 3,254 $ (1,299 ) $ 1,955 Total current derivative assets $ — $ — $ 3,254 $ 3,254 $ (1,299 ) 1,955 PPAs (a) 3,159 Current derivative instruments $ 5,114 Noncurrent derivative assets PPAs (a) $ 22,113 Noncurrent derivative instruments $ 22,113 Current derivative liabilities Other derivative instruments: Electric commodity $ — $ — $ 1,299 $ 1,299 $ (1,299 ) $ — Total current derivative liabilities $ — $ — $ 1,299 $ 1,299 $ (1,299 ) — PPAs (a) 3,565 Current derivative instruments $ 3,565 Noncurrent derivative liabilities PPAs (a) $ 23,513 Noncurrent derivative instruments $ 23,513 (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 balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Dec. 31, 2016. At Dec. 31, 2016, 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. 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 at Dec. 31, 2015: Dec. 31, 2015 Fair Value Fair Value Total Counterparty Netting (b) (Thousands of Dollars) Level 1 Level 2 Level 3 Total Current derivative assets Other derivative instruments: Electric commodity $ — $ — $ 8,980 $ 8,980 $ (3,920 ) $ 5,060 Total current derivative assets $ — $ — $ 8,980 $ 8,980 $ (3,920 ) 5,060 PPAs (a) 7,892 Current derivative instruments $ 12,952 Noncurrent derivative assets PPAs (a) $ 25,272 Noncurrent derivative instruments $ 25,272 Current derivative liabilities Other derivative instruments: Electric commodity $ — $ — $ 3,920 $ 3,920 $ (3,920 ) $ — Total current derivative liabilities $ — $ — $ 3,920 $ 3,920 $ (3,920 ) — PPAs (a) 3,565 Current derivative instruments $ 3,565 Noncurrent derivative liabilities PPAs (a) $ 27,078 Noncurrent derivative instruments $ 27,078 (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 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, 2015. At Dec. 31, 2015, 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. The following table presents the changes in Level 3 commodity derivatives for the years ended Dec. 31, 2016, 2015 and 2014: Year Ended Dec. 31 (Thousands of Dollars) 2016 2015 2014 Balance at Jan. 1 $ 5,060 $ 15,884 $ 9,933 Purchases 7,616 23,425 50,244 Settlements (41,923 ) (31,703 ) (44,283 ) Net transactions recorded during the period: Gains (losses) recognized as regulatory assets 31,202 (2,546 ) (10 ) Balance at Dec. 31 $ 1,955 $ 5,060 $ 15,884 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 years ended Dec. 31, 2016, 2015 and 2014. Fair Value of Long-Term Debt As of Dec. 31, 2016 and 2015, other financial instruments for which the carrying amount did not equal fair value were as follows: 2016 2015 (Thousands of Dollars) Carrying Amount Fair Value Carrying Amount Fair Value Long-term debt, including current portion (a) $ 1,635,858 $ 1,741,502 $ 1,538,522 $ 1,678,673 (a) Amounts reflect the classification of debt issuance costs as a deduction from the carrying amount of the related debt. See Note 2, Accounting Pronouncements for more information on the adoption of ASU No. 2015-03. The fair value of 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, 2016 and 2015, and given the observability of the inputs to these estimates, the fair values presented for long-term debt have been assigned a Level 2.

Rate Matters

Rate Matters	12 Months Ended
	Dec. 31, 2016
Public Utilities, General Disclosures [Abstract]
Rate Matters	Rate Matters Pending and Recently Concluded Regulatory Proceedings — PUCT Appeal of the Texas 2015 Electric Rate Case Decision — In 2014, SPS had requested an overall retail electric revenue rate increase of $64.8 million , which it subsequently revised to $42.1 million . In 2015, the PUCT approved an overall rate decrease of approximately $4.0 million , net of rate case expenses. In April 2016, SPS filed an appeal, with the Texas State District Court, of the PUCT’s order that had denied SPS’ request for rehearing on certain items in SPS’ Texas 2015 electric rate case related to capital structure, incentive compensation and wholesale load reductions. A decision by the Texas State District Court is pending. Texas 2016 Electric Rate Case — In February 2016, SPS filed a retail electric, base rate case in Texas with each of its Texas municipalities and the PUCT requesting an overall increase in annual base rate revenue of approximately $71.9 million , or 14.4 percent . The filing is based on a historic test year ended Sept. 30, 2015, a requested ROE of 10.25 percent , an electric rate base of approximately $1.7 billion , and an equity ratio of 53.97 percent . In September 2016, SPS revised its requested rate increase to $61.5 million and along with recovery of rate case expenses made for an overall revised request of $65.5 million . In December 2016, SPS reached an unopposed settlement that resolves all issues in the rate case. The following table reflects the total estimated impact: (Millions of Dollars) Settlement Base rate increase, retroactive to July 20, 2016 $ 35.2 Power factor revenues (a) 12.6 Rate case expenses to be addressed in a separate proceeding 4.0 Total estimated impact $ 51.8 (a) SPS’ request assumed customers would adjust their power factors, which would reduce revenue. To the extent power factor revenues are less than $12.6 million , a mechanism will be established to ensure SPS recovers this amount and effectively offset lower anticipated power factor charges. Additional key terms are as follows: • SPS’ next TCRF application will have a cap of $19 million in additional annual revenue and parties will make reasonable efforts to obtain PUCT approval within 100 days of SPS’ initial filing; • No disallowance of SPS’ requested capital additions; and • No restrictions on filing future rate cases or rate riders. Pursuant to legislation passed in Texas in 2015, the final rates established in the case will be effective retroactive to July 20, 2016. In December 2016, an ALJ approved interim rates, effective as of Dec. 10, 2016. In the fourth quarter of 2016, SPS deferred certain costs associated with this rate case. In January 2017, the PUCT approved the settlement and no refund of interim rates was necessary. SPS expects to file a surcharge to recover the additional revenue associated with final rates, for the period of July 20, 2016 through Dec. 9, 2016, by the third quarter of 2017. Texas 2016 TCRF Application — In February 2017, SPS filed an application with the PUCT to recover additional annual revenue of approximately $16.1 million through its TCRF, or 1.79 percent . The filing is based upon expenses and investments through Dec. 31, 2016. Based on the settlement agreement approved in the Texas 2016 electric rate case, SPS expects a PUCT decision and implementation of TCRF rates by mid-2017. Pending Regulatory Proceedings — NMPRC New Mexico 2016 Electric Rate Case — In November 2016, SPS filed an electric rate case with the NMPRC for an increase in base rates of approximately $41.4 million , representing a total revenue increase of approximately 10.9 percent . The rate filing is based on a future test year ending June 30, 2018, a requested return on equity of 10.1 percent , an equity ratio of 53.97 percent and an electric rate base of approximately $832 million . SPS has excluded fuel and purchased power costs from base rates. This base rate case also takes into account the decline in sales of 380 MW in 2017 from certain wholesale customers and seeks to adjust the service life of SPS’ Tolk power plant to a remaining life of 2030 based on the investments to provide cooling water and the risks of investments in additional environmental controls. The major components of the requested rate increase are summarized below: (Millions of Dollars) Request Capital expenditures $ 20.1 Allocator changes, including wholesale load reductions 11.5 Transmission expense, net of revenue, including charges paid to SPP for construction of regionally shared transmission projects 4.7 Depreciation, including adjustment of service life for the Tolk generating station 3.6 Rate case expenses 1.1 Other, net 0.4 Requested rate increase $ 41.4 Key dates in the procedural schedule are as follows: • Deadline for settlement — Feb. 28, 2017; • Staff and intervenor testimony — April 14, 2017; • Rebuttal testimony — May 3, 2017; • Hearings — May 15, 2017; and • An NMPRC decision and implementation of final rates is anticipated in the second half of 2017. Pending Regulatory Proceedings — FERC SPP Open Access Transmission Tariff (OATT) Upgrade Costs — Under the SPP OATT, costs of participant-funded, or “sponsored,” transmission upgrades may be recovered, in part, from other SPP customers whose transmission service depends on capacity enabled by the upgrade. The SPP OATT has allowed SPP to collect charges since 2008, but SPP had not been charging its customers any amounts attributable to these upgrades. In April 2016, SPP filed a request with the FERC for a waiver that would allow SPP to recover the charges not billed since 2008. The FERC approved the waiver request in July 2016. SPS and certain other parties requested rehearing of the FERC order. Amounts due to SPP are expected to be paid over a five -year period commencing November 2016 under an optional payment plan that was approved by the FERC in September 2016 and elected by SPS in October 2016. In October 2016, SPS filed applications for deferred accounting and future recovery of related costs in Texas and New Mexico. In November 2016, SPP billed SPS a net amount, for the period from 2008 through August 2016, of $12.8 million for these charges. In December 2016, SPS’ New Mexico application was consolidated with its base rate case and SPS’ Texas application was referred to the ALJ for hearing. A decision is expected in the first half of 2017. SPS anticipates these costs will be recoverable through regulatory mechanisms.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2016
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. 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. Most significant are the 345 KV transmission line from TUCO to Yoakum County to Hobbs Plant and the Hobbs Plant to China Draw 345 KV transmission line. 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 2017 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, 2016 , are as follows: (Millions of Dollars) Coal Natural gas Natural gas 2017 $ 195.2 $ 16.7 $ 22.8 2018 — — 20.8 2019 — — 21.4 2020 — — 21.4 2021 — — 16.3 Thereafter — — 58.2 Total $ 195.2 $ 16.7 $ 160.9 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 2033 for purchased power to meet system load and energy requirements and meet operating reserve obligations. In general, these agreements 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 $56.8 million , $56.7 million and $52.4 million in 2016 , 2015 and 2014 , respectively. At Dec. 31, 2016 , 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) Capacity 2017 $ 58.0 2018 57.0 2019 19.4 2020 11.6 2021 11.9 Thereafter 29.7 Total $ 187.6 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, vehicles, aircraft and power-operated equipment, are accounted for as operating leases. Total expenses under operating lease obligations were approximately $56.6 million , $54.5 million and $63.1 million for 2016 , 2015 and 2014 , respectively. These expenses include capacity payments for PPAs accounted for as operating leases of $50.6 million , $48.6 million and $57.1 million in 2016 , 2015 and 2014 , 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: (Millions of Dollars) Operating PPA (a) (b) Operating Leases Total 2017 $ 5.0 $ 51.5 $ 56.5 2018 5.7 50.7 56.4 2019 5.7 50.7 56.4 2020 5.6 50.7 56.3 2021 5.4 50.7 56.1 Thereafter 67.9 593.6 661.5 (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. In addition, certain solar PPAs provide SPS with an option to purchase emission allowances or sharing provisions related to production credits generated by the solar facility under contract. These specific PPAs create a variable interest in the 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 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 897 MW and 827 MW of capacity under long-term PPAs as of Dec. 31, 2016 and 2015 , respectively, with entities that have been determined to be variable interest entities. These agreements have expiration dates through the year 2041 . 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 December 2017 . 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 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. 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, its predecessors, or other entities; and third-party sites, such as landfills, for which SPS is alleged to be a PRP that sent 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 (CWA) Effluent Limitations Guidelines (ELG) — In 2015, the EPA issued a final ELG rule for power plants that use coal, natural gas, oil or nuclear materials as fuel and discharge treated effluent to surface waters as well as utility-owned landfills that receive coal combustion residuals. SPS has reviewed the final rule and does not anticipate costs of compliance will have a material impact on the results of operations, financial position or cash flows. Federal CWA Waters of the United States Rule — In June 2015, the EPA and the U.S. Army Corps of Engineers published a final rule that significantly expands the types of water bodies regulated under the CWA and broadens the scope of waters subject to federal jurisdiction. The expansion of the term “Waters of the U.S.” will subject more utility projects to federal CWA jurisdiction, thereby potentially delaying the siting of new generation projects, pipelines, transmission lines and distribution lines, as well as increasing project costs and expanding permitting and reporting requirements. In October 2015, the U.S. Court of Appeals for the Sixth Circuit issued a nationwide stay of the final rule and subsequently ruled that it, rather than the federal district courts, had jurisdiction over challenges to the rule. In January 2017, the U.S. Supreme Court agreed to resolve the dispute as to which court should hear challenges to the rule. A ruling is expected by June 2017. Air GHG Emission Standard for Existing Sources (Clean Power Plan or CPP) — In 2015, a final rule was published by the EPA for GHG emission standards for existing power plants. Under the rule, states were required to develop implementation plans by September 2016, with the possibility of an extension to September 2018, or submit to a federal plan for the state prepared by the EPA. Among other things, the rule requires that state plans include enforceable measures to ensure emissions from existing power plants achieve the EPA’s state-specific interim (2022-2029) and final (2030 and thereafter) emission performance targets. The CPP was challenged by multiple parties in the D.C. Circuit Court. In January 2016, the D.C. Circuit Court denied requests to stay the effectiveness of the rule. In February 2016, the U.S. Supreme Court issued an order staying the final CPP rule. In September 2016, the D.C. Circuit Court heard oral arguments in the consolidated challenges to the CPP. The stay will remain in effect until the D.C. Circuit Court reaches its decision and the U.S. Supreme Court either declines to review the lower court’s decision or reaches a decision of its own. During the pendency of the stay, states are not required to submit implementation plans and the EPA will not enforce deadlines or issue a federal plan for any state. The states served by SPS have suspended formal planning efforts. SPS has undertaken a number of initiatives that reduce GHG emissions and respond to state renewable and energy efficiency goals. The CPP could require additional emission reductions in states in which SPS operates. If state plans do not provide credit for the investments SPS has already made to reduce GHG emissions, or if they require additional initiatives or emission reductions, then their requirements would potentially impose additional substantial costs. Until SPS has more information about SIPs or the EPA finalizes its proposed federal plan for the states that do not develop related plans, SPS cannot predict the costs of compliance with the final rule once it takes effect. SPS believes compliance costs will be recoverable through regulatory mechanisms. If SPS’ regulators do not allow recovery of all or a part of the cost of capital investment or the O&M costs incurred to comply with the CPP or cost recovery is not provided in a timely manner, it could have a material impact on results of operations, financial position or cash flows. CSAPR — CSAPR addresses long range transport of PM and ozone by requiring reductions in SO 2 and NOx from utilities in the eastern half of the United States, including Texas, using an emissions trading program. CSAPR was adopted to address interstate emissions impacting downwind states’ attainment of the 1997 ozone NAAQS and the 1997 and 2006 particulate NAAQS. As the EPA revises NAAQS, it will consider whether to make any further reductions to CSAPR emission budgets and whether to change which states are included in the emissions trading program. In December 2015, the EPA proposed adjustments to CSAPR emission budgets which address attainment of the more stringent 2008 ozone NAAQS. In September 2016, the EPA adopted a final rule that reduced the ozone season emission budget for NOx in Texas by approximately 22 percent , which is expected to lead to increased costs to purchase emission allowances. In November 2016, the EPA proposed to remove Texas from the particle NAAQS program. If adopted as proposed, Texas would no longer be subject to the annual SO 2 and NOx emission budgets under CSAPR. SPS does not anticipate these increased costs to purchase emission allowances will have a material impact on the results of operations, financial position or cash flows. Regional Haze Rules — The regional haze program is designed to address widespread haze that results from emissions from a multitude of sources. The BART requirements of the EPA’s regional haze rules require the installation and operation of emission controls for industrial facilities emitting air pollutants that reduce visibility in national parks and wilderness areas. Under BART, regional haze plans identify facilities that will have to reduce SO 2 , NOx and PM emissions and set emission limits for those facilities. BART requirements can also be met through participation in interstate emission trading programs such as the CAIR and its successor, CSAPR. Texas’ first regional haze plan is still undergoing federal review as described below. Actions affecting Harrington Units: Texas 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 2014, the EPA proposed to approve the BART portion of the SIP, with substitution of CSAPR compliance for Texas’ reliance on CAIR. In January 2016, the EPA adopted a final rule that defers its approval of CSAPR compliance as BART until the EPA considers further adjustments to CSAPR emission budgets under the D.C. Circuit Court’s remand of the Texas SO 2 emission budgets. In June 2016, the EPA issued a memorandum which allows Texas to voluntarily adopt the CSAPR emission budgets limiting annual SO 2 and NOx emissions and rely on those emission budgets to satisfy Texas’ BART obligations under the regional haze rules. The Texas Commission on Environmental Quality (TCEQ) has not utilized this option. The EPA then published a proposed rule in January 2017 that could have the effect of requiring installation of dry scrubbers to reduce SO 2 emissions from Harrington Units 1 and 2. Investment costs associated with dry scrubbers for Harrington Units 1 and 2 could be approximately $400 million . The EPA’s deadline to issue a final BART rule for Texas is September 2017. Actions affecting Tolk units: In January 2016, the EPA adopted a final rule establishing a federal implementation plan for the state of Texas, which imposed SO 2 emission limitations that reflect the installation of dry scrubbers on Tolk Units 1 and 2, with compliance required by February 2021. Investment costs associated with dry scrubbers could be approximately $600 million . SPS appealed the EPA’s decision and requested a stay of the final rule. The Fifth Circuit granted the stay and decided that the Fifth Circuit is the appropriate venue for this case. The EPA sought a remand of its order and SPS and others have opposed the terms of that remand. A decision is expected in late 2017 or early 2018. It is likely that Texas and other affected entities including SPS would continue to challenge the determinations to date. The new Administration has not yet taken any public position regarding its views of the proposed and final regional haze regulations affecting SPS facilities in Texas. The risk of these controls being imposed along with the risk of investments to provide cooling water to Tolk have caused SPS to seek to decrease the remaining depreciable life of the Tolk units. Implementation of the NAAQS for SO 2 — The EPA adopted a more stringent NAAQS for SO 2 in 2010. The EPA is requiring states to evaluate areas in three phases. The first phase includes areas near SPS’ Tolk and Harrington plants. The Tolk and Harrington Plants utilize low sulfur coal to reduce SO 2 emissions. In June 2016, the EPA issued final designations which found the area near the Tolk plant to be meeting the NAAQS and the area near the Harrington plant as “unclassifiable.” The area near the Harrington plant is to be monitored for three years and a final designation is expected to be made by December 2020. If an area is designated nonattainment in 2020, the states will need to evaluate all SO 2 sources in the area. The state would then submit an implementation plan, which would be due by 2022, designed to achieve the NAAQS by 2025. The TCEQ could require additional SO 2 controls at Harrington as part of such a plan. SPS cannot evaluate the impacts until the designation of nonattainment areas is made, and any required state plans are developed. SPS believes that should SO 2 control systems be required or require upgrades for a plant, compliance costs or the costs of alternative cost-effective generation will be recoverable through regulatory mechanisms and therefore does not expect a material impact on results of operations, financial position or cash flows. Revisions to the NAAQS for Ozone — In 2015, the EPA revised the NAAQS for ozone by lowering the eight -hour standard from 75 parts per billion (ppb) to 70 ppb. In areas where SPS operates, current monitored air quality concentrations meet the 70 ppb level in the Texas panhandle. In documents issued with the new standard, the EPA projects this area will meet the new standard. Therefore, SPS does not expect a material impact on results of operations, financial position or cash flows. Asset Retirement Obligations Recorded AROs — AROs have been recorded for property related to the following: electric 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 electric production includes certain specific plants. AROs also have been recorded for steam production related to ash-containment facilities such as bottom ash ponds, evaporation ponds and solid waste landfills. An ARO was recognized for the removal of electric transmission and distribution equipment, which consists of many small potential obligations associated with PCBs, mineral oil, storage tanks, lithium batteries, mercury and street lighting lamps. The electric general ARO includes small obligations related to storage tanks. In April 2015, the EPA published the final rule regulating the management and disposal of coal combustion byproducts (e.g., coal ash) as a nonhazardous waste to the Federal Register. The rule became effective in October 2015. No cash flow revisions were necessary, as a result of the final rule. A reconciliation of SPS’ AROs for the years ended Dec. 31, 2016 and 2015 is as follows: (Thousands of Dollars) Beginning Balance Jan. 1, 2016 Accretion Cash Flow Revisions Ending Balance Dec. 31, 2016 (a) Electric plant Steam production asbestos $ 17,981 $ 1,089 $ — $ 19,070 Steam production ash containment 1,513 80 — 1,593 Electric distribution 6,559 240 — 6,799 Other 1,180 42 (21 ) 1,201 Total liability $ 27,233 $ 1,451 $ (21 ) $ 28,663 (a) There were no ARO liabilities recognized or settled during the year ended Dec. 31, 2016. (Thousands of Dollars) Beginning Balance Jan. 1, 2015 Accretion Cash Flow Revisions Ending Balance Dec. 31, 2015 (a) Electric plant Steam production asbestos $ 16,957 $ 1,024 $ — $ 17,981 Steam production ash containment 1,609 85 (181 ) 1,513 Electric distribution 6,327 232 — 6,559 Other 1,138 42 — 1,180 Total liability $ 26,031 $ 1,383 $ (181 ) $ 27,233 (a) There were no ARO liabilities recognized or settled during the year ended Dec. 31, 2015. Indeterminate AROs — Outside of the known and recorded asbestos AROs, other plants or buildings may contain asbestos due to the age of many of SPS’ facilities, but no confirmation or measurement of the amount of asbestos or cost of removal could be determined as of Dec. 31, 2016. Therefore, an ARO has not been recorded for these facilities. Removal Costs — SPS records a regulatory liability for the plant removal costs of generation, transmission and distribution facilities that are recovered currently in rates. Generally, the accrual of future non-ARO removal obligations is not required. However, long-standing ratemaking practices approved by applicable state and federal regulatory commissions have allowed provisions for such costs in historical depreciation rates. These removal costs have accumulated over a number of years based on varying rates as authorized by the appropriate regulatory entities. Given the long time periods over which the amounts were accrued and the changing of rates over time, 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, 2016 and 2015 were $209 million and $204 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. Other Contingencies See Note 10 for further discussion.

Regulatory Assets and Liabiliti

Regulatory Assets and Liabilities	12 Months Ended
	Dec. 31, 2016
Regulatory Assets and Liabilities Disclosure [Abstract]
Regulatory Assets and Liabilities	12. Regulatory Assets and Liabilities 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, 2016 and 2015 are: (Thousands of Dollars) See Remaining Dec. 31, 2016 Dec. 31, 2015 Regulatory Assets Current Noncurrent Current Noncurrent Pension and retiree medical obligations (a) 7 Various $ 13,986 $ 234,171 $ 15,632 $ 223,122 Recoverable deferred taxes on AFUDC recorded in plant 1 Plant lives — 44,258 — 39,368 Net AROs (b) 11 Plant lives — 24,352 — 23,014 Renewable resources and environmental initiatives 11 One to four years 3,580 2,900 3,740 2,019 Conservation programs (c) 1 One to three years 3,754 2,431 5,137 3,859 Losses on reacquired debt 4 Term of related debt 127 1,617 850 1,743 Other Various 17,274 36,954 6,182 8,689 Total regulatory assets $ 38,721 $ 346,683 $ 31,541 $ 301,814 (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. 31, 2016 and 2015 are: (Thousands of Dollars) See Remaining Dec. 31, 2016 Dec. 31, 2015 Regulatory Liabilities Current Noncurrent Current Noncurrent Plant removal costs 11 Plant lives $ — $ 208,638 $ — $ 203,954 Revenue subject to refund 10 One to two years 5,093 3,602 20,647 1,080 Gain from asset sales 10 Various — 2,530 2,640 2,584 Deferred electric energy costs 1 Less than one year 32,451 — 61,041 — Contract valuation adjustments (a) 1, 9 Term of related contract 1,955 — 9,387 — Renewable resources and environmental initiatives 11 One to two years 1,075 — 2,960 880 Other Various 1,003 18,684 1,630 21,086 Total regulatory liabilities (b) $ 41,577 $ 233,454 $ 98,305 $ 229,584 (a) Includes the fair value of certain long-term PPAs used to meet energy capacity requirements. (b) Revenue subject to refund of $0 million and $3.9 million for 2016 and 2015, respectively, is included in other current liabilities. At Dec. 31, 2016 and 2015 , approximately $65 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, 2016
Stockholders' Equity Note [Abstract]
Other Comprehensive Income	13. Other Comprehensive Income Changes in accumulated other comprehensive loss, net of tax, for the years ended Dec. 31, 2016 and 2015 were as follows: Year Ended Dec. 31, 2016 (Thousands of Dollars) Gains and Losses on Cash Flow Hedges Defined Benefit Pension and Postretirement Items Total Accumulated other comprehensive loss at Jan. 1 $ (817 ) $ (464 ) $ (1,281 ) Other comprehensive loss before reclassifications — (148 ) (148 ) Losses reclassified from net accumulated other comprehensive loss 139 — 139 Net current period other comprehensive income (loss) 139 (148 ) (9 ) Accumulated other comprehensive loss at Dec. 31 $ (678 ) $ (612 ) $ (1,290 ) Year Ended Dec. 31, 2015 (Thousands of Dollars) Gains and Losses on Cash Flow Hedges Defined Benefit Pension and Postretirement Items Total Accumulated other comprehensive loss at Jan. 1 $ (989 ) $ — $ (989 ) Other comprehensive loss before reclassifications — (464 ) (464 ) Losses reclassified from net accumulated other comprehensive loss 172 — 172 Net current period other comprehensive income (loss) 172 (464 ) (292 ) Accumulated other comprehensive loss at Dec. 31 $ (817 ) $ (464 ) $ (1,281 ) Reclassifications from accumulated other comprehensive loss for the years ended Dec. 31, 2016 and 2015 were as follows: Amounts Reclassified from Accumulated (Thousands of Dollars) Year Ended Dec. 31, 2016 Year Ended Dec. 31, 2015 Losses on cash flow hedges: Interest rate derivatives $ 219 (a) $ 269 (a) Total, pre-tax 219 269 Tax benefit (80 ) (97 ) Total amounts reclassified, net of tax $ 139 $ 172 (a) Included in interest charges.

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2016
Related Party Transactions [Abstract]
Related Party Transactions	Related Party Transactions Xcel Energy Services Inc. provides management, administrative and other services for the subsidiaries of Xcel Energy Inc., including 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) 2016 2015 2014 Operating revenues: Electric $ 56 $ — $ 23 Operating expenses: Purchased power 8,809 8,632 9,614 Other operating expenses — paid to Xcel Energy Services Inc. 188,175 197,134 145,917 Interest expense 189 156 73 Interest income — 6 3 Accounts receivable and payable with affiliates at Dec. 31 were: 2016 2015 (Thousands of Dollars) Accounts Accounts Accounts Accounts NSP-Minnesota $ 935 $ — $ 1,066 $ — NSP-Wisconsin — 333 — 71 PSCo — 745 — 414 Other subsidiaries of Xcel Energy Inc. 14 13,336 13 28,650 $ 949 $ 14,414 $ 1,079 $ 29,135

Summarized Quarterly Financial

Summarized Quarterly Financial Data (Unaudited)	12 Months Ended
	Dec. 31, 2016
Quarterly Financial Information Disclosure [Abstract]
Summarized Quarterly Financial Data (Unaudited)	Summarized Quarterly Financial Data (Unaudited) Quarter Ended (Thousands of Dollars) March 31, 2016 June 30, 2016 Sept. 30, 2016 Dec. 31, 2016 Operating revenues $ 390,839 $ 440,445 $ 554,926 $ 464,749 Operating income 53,569 68,386 122,362 62,964 Net income 22,523 32,211 68,346 29,077 Quarter Ended (Thousands of Dollars) March 31, 2015 June 30, 2015 Sept. 30, 2015 Dec. 31, 2015 Operating revenues $ 423,829 $ 422,985 $ 530,752 $ 409,652 Operating income 49,759 53,132 117,076 54,498 Net income 20,247 22,576 61,815 22,625

Schedule II, Valuation and Qual

Schedule II, Valuation and Qualifying Accounts	12 Months Ended
	Dec. 31, 2016
Valuation and Qualifying Accounts [Abstract]
Schedule II, Valuation and Qualifying Accounts	SOUTHWESTERN PUBLIC SERVICE CO. VALUATION AND QUALIFYING ACCOUNTS YEARS ENDED DEC. 31, 2016, 2015 AND 2014 (amounts in thousands) Additions Balance at Jan. 1 Charged to Costs and Expenses Charged to Other Accounts (a) Deductions from Reserves (b) Balance at Dec. 31 Allowance for bad debts: 2016 $ 5,888 $ 6,066 $ 907 $ 6,482 $ 6,379 2015 5,839 4,655 1,036 5,642 5,888 2014 5,475 4,137 1,089 4,862 5,839 (a) Recovery of amounts previously written off. (b) Deductions relate primarily to bad debt write-offs.

Summary of Significant Accoun28

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2016
Accounting Policies [Abstract]
Business and System of Accounts	Business and System of Accounts — SPS is 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 or potential disallowances, AROs, certain regulatory assets and liabilities, tax provisions, uncollectible amounts, environmental costs, unbilled revenues, jurisdictional fuel and energy cost allocations and actuarially determined benefit costs. The recorded estimates are revised when better information becomes available or when actual amounts can be determined. Those revisions can affect operating results.
Regulatory Accounting	Regulatory Accounting — 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 or OCI, are deferred as regulatory liabilities based on the expectation the amounts will be returned to customers in future rates, or because the amounts were collected in rates prior to the costs being incurred. Estimates of recovering deferred costs and returning deferred credits are based on specific ratemaking decisions or precedent for each item. Regulatory assets and liabilities are amortized consistent with the treatment in the rate setting process. If restructuring or other changes in the regulatory environment occur, 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. SPS recognizes sales to both native load and other end use customers on a gross basis. 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. Other revenues and charges related to participating and transacting in RTOs are recorded on a net basis in 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 motor, air conditioner and lighting upgrades, as well as residential rebates for participation in air conditioner interruption and home weatherization. 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. Recorded revenues for incentive programs designed for recovery of lost margins and/or conservation performance incentives are limited to amounts expected to be collected within 24 months from 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 is tested for impairment when it is determined that the carrying value of the assets may not be recoverable. A loss is recognized in the current period if it becomes probable that part of a cost of a plant under construction or recently completed plant will be disallowed for recovery from customers and a reasonable estimate of the disallowance can be made. For investments in property, plant and equipment that are abandoned and not expected to go into service, incurred costs and related deferred tax amounts are compared to the discounted estimated future rate recovery, and a loss is recognized, if necessary. SPS records depreciation expense related to its plant using the straight-line method over the plant’s useful life. Actuarial life studies are performed and submitted to the state and federal commissions for review. Upon acceptance by the various commissions, the resulting lives and net salvage rates are used to calculate depreciation. Depreciation expense, expressed as a percentage of average depreciable property, was 2.7 , 2.6 and 2.5 percent for the years ended Dec. 31, 2016, 2015 and 2014, 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 accounts for AROs under accounting guidance that requires a liability for the fair value of an ARO to be recognized in the period in which it is incurred if it can be reasonably estimated, with the offsetting associated asset retirement costs capitalized as a long-lived asset. The liability is generally increased over time by applying the effective interest method of accretion, and the capitalized costs are depreciated over the useful life of the long-lived asset. Changes resulting from revisions to the timing or amount of expected asset retirement cash flows are recognized as an increase or a decrease in the ARO. SPS also recovers through rates certain future plant removal costs in addition to AROs. The accumulated removal costs for these obligations are reflected in the balance sheets as a regulatory liability. See Note 11 for further discussion of AROs.
Income Taxes	Income Taxes — 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 ratemaking purposes, the reversal of some temporary differences are accounted for as current income tax expense. Tax credits are recorded when earned unless there is a requirement to defer the benefit and amortize it over the book depreciable lives of the related property. The requirement to defer and amortize tax credits only applies to federal ITCs related to public utility property. Utility rate regulation also has resulted in the recognition of certain regulatory assets and liabilities related to income taxes, which are summarized in Note 12. 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 and interest rate activities, including forward contracts, futures, swaps and options. All derivative instruments not designated and qualifying for the normal purchases and normal sales exception, as defined by the accounting guidance for derivatives and hedging, are recorded on the 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. 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. 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.
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 NAVs. For interest rate derivatives, quoted prices based primarily on observable market interest rate curves are used as a primary input to establish fair value. For commodity derivatives, the most observable inputs available are generally used to determine the fair value of each contract. In the absence of a quoted price for an identical contract in an active market, 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 SO 2 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 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 be extended are treated as a capitalized cost of plant retirement. The depreciation expense levels recoverable in rates include a provision for removal expenses, which may include final remediation costs. Removal costs recovered in rates before the related costs are incurred are classified as a regulatory liability. See Note 11 for further discussion of environmental costs.
Benefit Plans and Other Postretirement Benefits	Benefit Plans and Other Postretirement Benefits — 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.
Reclassifications	Reclassifications — Due to adoption of new accounting pronouncements, certain previously reported amounts have been reclassified to conform to the current year presentation.
Subsequent Events	Subsequent Events — Management has evaluated the impact of events occurring after Dec. 31, 2016 up to the date of issuance of these 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, 2016
Balance Sheet Related Disclosures [Abstract]
Accounts Receivable, Net	(Thousands of Dollars) Dec. 31, 2016 Dec. 31, 2015 Accounts receivable, net Accounts receivable $ 80,569 $ 77,054 Less allowance for bad debts (6,379 ) (5,888 ) $ 74,190 $ 71,166
Inventories	(Thousands of Dollars) Dec. 31, 2016 Dec. 31, 2015 Inventories Materials and supplies $ 25,453 $ 24,888 Fuel 13,052 12,658 $ 38,505 $ 37,546
Property, Plant and Equipment, Net	(Thousands of Dollars) Dec. 31, 2016 Dec. 31, 2015 Property, plant and equipment, net Electric plant $ 6,362,189 $ 5,933,764 Construction work in progress 260,327 236,697 Total property, plant and equipment 6,622,516 6,170,461 Less accumulated depreciation (1,926,697 ) (1,821,638 ) $ 4,695,819 $ 4,348,823

Borrowings and Other Financin30

Borrowings and Other Financing Instruments (Tables)	12 Months Ended
	Dec. 31, 2016
Borrowings and Other Financing Instruments [Abstract]
Credit Facilities	At Dec. 31, 2016 , SPS had the following committed credit facility available (in millions): Credit Facility (a) Drawn (b) Available $ 400 $ 55.0 $ 345.0 (a) This credit facility matures in June 2021 . (b) Includes outstanding commercial paper and letters of credit.
Money Pool
Borrowings and Other Financing Instruments [Abstract]
Short-Term Borrowings	Money pool borrowings for SPS were as follows: (Amounts in Millions, Except Interest Rates) Three Months Ended Dec. 31, 2016 Borrowing limit $ 100 Amount outstanding at period end — Average amount outstanding 20 Maximum amount outstanding 64 Weighted average interest rate, computed on a daily basis 0.83 % Weighted average interest rate at period end N/A (Amounts in Millions, Except Interest Rates) Twelve Months Ended Dec. 31, 2016 Twelve Months Ended Dec. 31, 2015 Twelve Months Ended Dec. 31, 2014 Borrowing limit $ 100 $ 100 $ 100 Amount outstanding at period end — — 16 Average amount outstanding 28 21 9 Maximum amount outstanding 100 100 100 Weighted average interest rate, computed on a daily basis 0.67 % 0.40 % 0.22 % Weighted average interest rate at end of period N/A N/A 0.45
Commercial Paper
Borrowings and Other Financing Instruments [Abstract]
Short-Term Borrowings	Commercial paper outstanding for SPS was as follows: (Amounts in Millions, Except Interest Rates) Three Months Ended Dec. 31, 2016 Borrowing limit $ 400 Amount outstanding at period end 50 Average amount outstanding 19 Maximum amount outstanding 75 Weighted average interest rate, computed on a daily basis 0.74 % Weighted average interest rate at period end 0.95 (Amounts in Millions, Except Interest Rates) Twelve Months Ended Dec. 31, 2016 Twelve Months Ended Dec. 31, 2015 Twelve Months Ended Dec. 31, 2014 Borrowing limit $ 400 $ 400 $ 400 Amount outstanding at period end 50 15 37 Average amount outstanding 43 100 83 Maximum amount outstanding 140 246 241 Weighted average interest rate, computed on a daily basis 0.67 % 0.46 % 0.26 % Weighted average interest rate at end of period 0.95 0.60 0.47

Preferred Stock (Tables)

Preferred Stock (Tables)	12 Months Ended
	Dec. 31, 2016
Equity [Abstract]
Preferred Stock	SPS has authorized the issuance of preferred stock. Preferred Par Value Preferred 10,000,000 $ 1.00 None

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2016
Income Tax Disclosure [Abstract]
Reconciliation of Unrecognized Tax Benefits	A reconciliation of the amount of unrecognized tax benefit is as follows: (Millions of Dollars) Dec. 31, 2016 Dec. 31, 2015 Unrecognized tax benefit — Permanent tax positions $ 4.5 $ 2.6 Unrecognized tax benefit — Temporary tax positions 24.2 22.1 Total unrecognized tax benefit $ 28.7 $ 24.7 A reconciliation of the beginning and ending amount of unrecognized tax benefit is as follows: (Millions of Dollars) 2016 2015 2014 Balance at Jan. 1 $ 24.7 $ 13.2 $ 4.1 Additions based on tax positions related to the current year 1.4 4.2 8.6 Reductions based on tax positions related to the current year — (0.6 ) — Additions for tax positions of prior years 3.9 9.0 2.3 Reductions for tax positions of prior years (1.3 ) (1.1 ) (0.3 ) Settlements with taxing authorities — — (0.2 ) Lapse of applicable statutes of limitations — — (1.3 ) Balance at Dec. 31 $ 28.7 $ 24.7 $ 13.2
Tax Benefits Associated with NOL and Tax Credit Carryforwards	The unrecognized tax benefit amounts were reduced by the tax benefits associated with NOL and tax credit carryforwards. The amounts of tax benefits associated with NOL and tax credit carryforwards are as follows: (Millions of Dollars) Dec. 31, 2016 Dec. 31, 2015 NOL and tax credit carryforwards $ (5.9 ) $ (5.0 )
Interest Payable related to Unrecognized Tax Benefits [Table Text Block]	The payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryforwards. A reconciliation of the beginning and ending amount of the payable for interest related to unrecognized tax benefits are as follows: (Millions of Dollars) 2016 2015 2014 Payable for interest related to unrecognized tax benefits at Jan. 1 $ — $ (0.1 ) $ — Interest (expense) income related to unrecognized tax benefits (0.9 ) 0.1 (0.1 ) Payable for interest related to unrecognized tax benefits at Dec. 31 $ (0.9 ) $ — $ (0.1 )
NOL and Tax Credit Carryforwards	Other Income Tax Matters — NOL amounts represent the amount of the tax loss that is carried forward and tax credits represent the deferred tax asset. NOL and tax credit carryforwards as of Dec. 31 were as follows: (Millions of Dollars) 2016 2015 Federal NOL carryforward $ 275 $ 306 Federal tax credit carryforwards 4 3 State NOL carryforwards 60 79 Valuation allowances for state NOL carryforwards — (11 )
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: 2016 2015 2014 Federal statutory rate 35.0 % 35.0 % 35.0 % Increases (decreases) in tax from: State income taxes, net of federal income tax benefit 1.5 2.6 3.4 Change in unrecognized tax benefits 0.8 0.5 0.2 Regulatory differences — utility plant items (1.0 ) (0.8 ) (1.6 ) Tax credits recognized, net of federal income tax expense (0.5 ) (0.3 ) (0.4 ) Other, net (0.7 ) 0.1 0.1 Effective income tax rate 35.1 % 37.1 % 36.7 %
Schedule of Components of Income Tax Expense (Benefit)	The components of income tax expense for the years ending Dec. 31 were: (Thousands of Dollars) 2016 2015 2014 Current federal tax benefit $ (40,853 ) $ (1,327 ) $ (57,201 ) Current state tax (benefit) expense (2,929 ) 2,448 2,512 Current change in unrecognized tax expense 3,126 11,281 6,715 Deferred federal tax expense 116,404 67,640 121,882 Deferred state tax expense 7,757 5,399 8,025 Deferred change in unrecognized tax benefit (1,178 ) (10,203 ) (6,390 ) Deferred investment tax credits (213 ) (213 ) (341 ) Total income tax expense $ 82,114 $ 75,025 $ 75,202 The components of deferred income tax expense for the years ending Dec. 31 were: (Thousands of Dollars) 2016 2015 2014 Deferred tax expense excluding items below $ 128,393 $ 63,453 $ 124,875 Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities (5,416 ) (780 ) (1,262 ) Tax benefit (expense) allocated to other comprehensive income and other 6 163 (96 ) Deferred tax expense $ 122,983 $ 62,836 $ 123,517
Schedule of Deferred Tax Assets and Liabilities	The components of the net deferred tax liability at Dec. 31 were as follows: (Thousands of Dollars) 2016 2015 Deferred tax liabilities: Differences between book and tax bases of property $ 1,034,675 $ 945,142 Employee benefits 42,239 50,097 Other 35,975 18,260 Total deferred tax liabilities $ 1,112,889 $ 1,013,499 Deferred tax assets: NOL carryforward $ 100,179 $ 112,060 Deferred fuel costs 10,226 23,127 Regulatory liabilities 3,380 10,480 Other 9,967 7,088 Total deferred tax assets $ 123,752 $ 152,755 Net deferred tax liability $ 989,137 $ 860,744

Benefit Plans and Other Postr33

Benefit Plans and Other Postretirement Benefits (Tables)	12 Months Ended
	Dec. 31, 2016
Benefit Plans and Other Postretirement Benefits [Abstract]
Projected Benefit Payments for the Pension and Postretirement Benefit Plans	The following table lists SPS’ projected benefit payments for the pension and postretirement benefit plans: (Thousands of Dollars) Projected Gross Projected Expected Net Projected 2017 $ 28,596 $ 3,420 $ 24 $ 3,396 2018 28,086 3,203 26 3,177 2019 28,545 3,008 24 2,984 2020 29,567 3,015 25 2,990 2021 29,716 3,096 26 3,070 2022-2026 156,673 14,135 148 13,987
Pension Plans
Benefit Plans and Other Postretirement Benefits [Abstract]
Target Asset Allocations and Plan Assets Measured at Fair Value	The following table presents the target pension asset allocations for SPS at Dec. 31 for the upcoming year: 2016 2015 Domestic and international equity securities 36 % 36 % Long-duration fixed income and interest rate swap securities 31 31 Short-to-intermediate fixed income securities 15 12 Alternative investments 16 19 Cash 2 2 Total 100 % 100 % 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, 2016 and 2015 : Dec. 31, 2016 (Thousands of Dollars) Level 1 Level 2 Level 3 Investments Measured at NAV (a) Total Cash equivalents $ 29,237 $ — $ — $ — $ 29,237 Commingled funds: U.S. equity funds — — — 62,899 62,899 Non U.S. equity funds — — — 46,403 46,403 U.S. corporate bond funds — — — 41,226 41,226 Emerging market equity funds — — — 24,637 24,637 Emerging market debt funds — — — 20,399 20,399 Commodity funds — — — 2,876 2,876 Private equity investments — — — 12,098 12,098 Real estate — — — 23,232 23,232 Other commingled funds — — — 28,247 28,247 Debt securities: Government securities — 38,105 — — 38,105 U.S. corporate bonds — 36,293 — — 36,293 Non U.S. corporate bonds — 5,818 — — 5,818 Mortgage-backed securities — 821 — — 821 Asset-backed securities — 389 — — 389 Equity securities: U.S. equities 10,477 — — — 10,477 Other — (2,762 ) — — (2,762 ) Total $ 39,714 $ 78,664 $ — $ 262,017 $ 380,395 (a) Based on the requirements of ASU No. 2015-07, investments measured at fair value using a NAV methodology have not been classified in the fair value hierarchy. See Note 2 for further information on the adoption of ASU No. 2015-07. Dec. 31, 2015 (Thousands of Dollars) Level 1 Level 2 Level 3 Investments Measured at NAV (a) Total Cash equivalents $ 22,999 $ — $ — $ — $ 22,999 Derivatives — 553 — — 553 Commingled funds: U.S. equity funds — — — 55,533 55,533 Non U.S. equity funds — — — 53,449 53,449 U.S. corporate bond funds — — — 32,020 32,020 Emerging market equity funds — — — 23,891 23,891 Emerging market debt funds — — — 23,169 23,169 Commodity funds — — — 7,884 7,884 Private equity investments — — — 19,114 19,114 Real estate — — — 27,690 27,690 Other commingled funds — — — 29,793 29,793 Debt securities: Government securities — 37,495 — — 37,495 U.S. corporate bonds — 28,826 — — 28,826 Non U.S. corporate bonds — 4,626 — — 4,626 Asset-backed securities — 323 — — 323 Equity securities: U.S. equities 13,492 — — — 13,492 Other — (1,944 ) — — (1,944 ) Total $ 36,491 $ 69,879 $ — $ 272,543 $ 378,913 (a) Based on the requirements of ASU No. 2015-07, investments measured at fair value using a NAV methodology have not been classified in the fair value hierarchy. See Note 2 for further information on the adoption of ASU No. 2015-07.
Change in Projected Benefit Obligation	A comparison of the actuarially computed pension benefit obligation and plan assets for SPS is presented in the following table: (Thousands of Dollars) 2016 2015 Accumulated Benefit Obligation at Dec. 31 $ 453,317 $ 429,726 Change in Projected Benefit Obligation: Obligation at Jan. 1 $ 467,394 $ 500,690 Service cost 9,761 11,006 Interest cost 21,259 20,184 Actuarial loss (gain) 25,053 (35,154 ) Transfer to other plan (3,305 ) (2,843 ) Benefit payments (36,561 ) (26,489 ) Obligation at Dec. 31 $ 483,601 $ 467,394
Change in Fair Value of Plan Assets	(Thousands of Dollars) 2016 2015 Change in Fair Value of Plan Assets: Fair value of plan assets at Jan. 1 $ 378,913 $ 402,269 Actual return (loss) on plan assets 23,306 (6,013 ) Employer contributions 18,088 11,651 Transfer to other plan (3,351 ) (2,505 ) Benefit payments (36,561 ) (26,489 ) Fair value of plan assets at Dec. 31 $ 380,395 $ 378,913
Funded Status of Plans	(Thousands of Dollars) 2016 2015 Funded Status of Plans at Dec. 31: Funded status (a) $ (103,206 ) $ (88,481 ) (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) 2016 2015 Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost: Net loss $ 247,381 $ 236,107
Amounts Not Yet Recognized as Components of Net Periodic Benefit Costs Recorded on the Balance Sheet Based Upon Expected Recovery in Rates	(Thousands of Dollars) 2016 2015 Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost Have Been Recorded as Follows Based Upon Expected Recovery in Rates: Current regulatory assets $ 13,524 $ 13,690 Noncurrent regulatory assets 233,857 222,417 Total $ 247,381 $ 236,107
Schedule of Assumptions Used	2016 2015 2014 Significant Assumptions Used to Measure Costs: Discount rate 4.66 % 4.11 % 4.75 % Expected average long-term increase in compensation level 4.00 3.75 3.75 Expected average long-term rate of return on assets 6.78 7.22 6.90 Measurement date Dec. 31, 2016 Dec. 31, 2015 2016 2015 Significant Assumptions Used to Measure Benefit Obligations: Discount rate for year-end valuation 4.13 % 4.66 % Expected average long-term increase in compensation level 3.75 4.00 Mortality table RP-2014 RP-2014
Components of Net Periodic Benefit Costs	Benefit Costs — The components of SPS’ net periodic pension cost were: (Thousands of Dollars) 2016 2015 2014 Service cost $ 9,761 $ 11,006 $ 9,184 Interest cost 21,259 20,184 20,444 Expected return on plan assets (27,602 ) (28,610 ) (26,179 ) Amortization of prior service cost — 39 54 Amortization of net loss 11,986 15,087 13,326 Net periodic pension cost 15,404 17,706 16,829 Credits not recognized due to effects of regulation 2,042 2,597 3,170 Net benefit cost recognized for financial reporting $ 17,446 $ 20,303 $ 19,999
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’ proportionate allocation of the total postretirement benefit plan assets that are measured at fair value as of Dec. 31, 2016 and 2015 : Dec. 31, 2016 (Thousands of Dollars) Level 1 Level 2 Level 3 Investments Measured at NAV (a) Total Cash equivalents $ 1,966 $ — $ — $ — $ 1,966 Insurance contracts — 4,519 — — 4,519 Commingled funds: U.S. equity funds — — — 5,208 5,208 U.S fixed income funds — — — 2,593 2,593 Emerging market debt funds — — — 2,911 2,911 Other commingled funds — — — 5,258 5,258 Debt securities: Government securities — 3,611 — — 3,611 U.S. corporate bonds — 5,962 — — 5,962 Non U.S. corporate bonds — 1,653 — — 1,653 Asset-backed securities — 1,810 — — 1,810 Mortgage-backed securities — 2,748 — — 2,748 Equity securities: Non U.S. equities 3,919 — — — 3,919 Other — 139 — — 139 Total $ 5,885 $ 20,442 $ — $ 15,970 $ 42,297 (a) Based on the requirements of ASU No. 2015-07, investments measured at fair value using a NAV methodology have not been classified in the fair value hierarchy. See Note 2 for further information on the adoption of ASU No. 2015-07. Dec. 31, 2015 (Thousands of Dollars) Level 1 Level 2 Level 3 Investments Measured at NAV (a) Total Cash equivalents $ 1,873 $ — $ — $ — $ 1,873 Insurance contracts — 4,501 — — 4,501 Commingled funds: U.S. equity funds — — — 3,643 3,643 Non U.S. equity funds — — — 3,204 3,204 U.S fixed income funds — — — 2,311 2,311 Emerging market equity funds — — — 1,058 1,058 Emerging market debt funds — — — 3,401 3,401 Other commingled funds — — — 5,910 5,910 Debt securities: Government securities — 3,742 — — 3,742 U.S. corporate bonds — 5,710 — — 5,710 Non U.S. corporate bonds — 1,239 — — 1,239 Asset-backed securities — 2,736 — — 2,736 Mortgage-backed securities — 3,396 — — 3,396 Other — (40 ) — — (40 ) Total $ 1,873 $ 21,284 $ — $ 19,527 $ 42,684 (a) Based on the requirements of ASU No. 2015-07, investments measured at fair value using a NAV methodology have not been classified in the fair value hierarchy. See Note 2 for further information on the adoption of ASU No. 2015-07. The following table presents the target postretirement asset allocations for Xcel Energy Inc. and SPS at Dec. 31 for the upcoming year: 2016 2015 Domestic and international equity securities 25 % 25 % Short-to-intermediate fixed income securities 57 57 Alternative investments 13 13 Cash 5 5 Total 100 % 100 %
Change in Projected Benefit Obligation	A comparison of the actuarially computed benefit obligation and plan assets for SPS is presented in the following table: (Thousands of Dollars) 2016 2015 Change in Projected Benefit Obligation: Obligation at Jan. 1 $ 40,864 $ 44,342 Service cost 775 954 Interest cost 1,821 1,745 Medicare subsidy reimbursements 31 45 Plan participants’ contributions 653 687 Actuarial loss (gain) 1,293 (3,793 ) Benefit payments (3,577 ) (3,116 ) Obligation at Dec. 31 $ 41,860 $ 40,864
Change in Fair Value of Plan Assets	(Thousands of Dollars) 2016 2015 Change in Fair Value of Plan Assets: Fair value of plan assets at Jan. 1 $ 42,684 $ 45,356 Actual return (loss) on plan assets 1,978 (421 ) Plan participants’ contributions 653 687 Employer contributions 559 178 Benefit payments (3,577 ) (3,116 ) Fair value of plan assets at Dec. 31 $ 42,297 $ 42,684
Funded Status of Plans	(Thousands of Dollars) 2016 2015 Funded Status of Plans at Dec. 31: Funded status (a) $ 437 $ 1,820 (a) Amounts are recognized in noncurrent assets on SPS’ balance sheet as of Dec. 31, 2016 and 2015.
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost	(Thousands of Dollars) 2016 2015 Amounts Not Yet Recognized as Components of Net Periodic Benefit Credit: Net gain $ (12,595 ) $ (14,870 ) Prior service credit (2,630 ) (3,031 ) Total $ (15,225 ) $ (17,901 )
Amounts Not Yet Recognized as Components of Net Periodic Benefit Costs Recorded on the Balance Sheet Based Upon Expected Recovery in Rates	(Thousands of Dollars) 2016 2015 Amounts Not Yet Recognized as Components of Net Periodic Benefit Credit Have Been Recorded as Follows Based Upon Expected Recovery in Rates: Current regulatory liabilities $ (1,004 ) $ (985 ) Noncurrent regulatory liabilities (14,221 ) (16,916 ) Total $ (15,225 ) $ (17,901 )
Schedule of Assumptions Used	2016 2015 2014 Significant Assumptions Used to Measure Costs: Discount rate 4.65 % 4.08 % 4.82 % Expected average long-term rate of return on assets 5.80 5.80 7.20 Measurement date Dec. 31, 2016 Dec. 31, 2015 2016 2015 Significant Assumptions Used to Measure Benefit Obligations: Discount rate for year-end valuation 4.13 % 4.65 % Mortality table RP 2014 RP 2014 Health care costs trend rate — initial 5.50 % 6.00 %
Effects of One-Percent Change in Assumed Health Care Cost Trend Rate	A one-percent change in the assumed health care cost trend rate would have the following effects on SPS: One-Percentage Point (Thousands of Dollars) Increase Decrease APBO $ 3,979 $ (3,389 ) Service and interest components 273 (231 )
Components of Net Periodic Benefit Costs	The components of SPS’ net periodic postretirement benefit costs were: (Thousands of Dollars) 2016 2015 2014 Service cost $ 775 $ 954 $ 1,246 Interest cost 1,821 1,745 2,572 Expected return on plan assets (2,377 ) (2,540 ) (3,247 ) Amortization of prior service credit (401 ) (401 ) (401 ) Amortization of net gain (583 ) (639 ) (321 ) Net periodic postretirement benefit credit $ (765 ) $ (881 ) $ (151 )

Other Income, Net (Tables)

Other Income, Net (Tables)	12 Months Ended
	Dec. 31, 2016
Other Income and Expenses [Abstract]
Other Income, Net	Other income (expense), net for the years ended Dec. 31 consisted of the following: (Thousands of Dollars) 2016 2015 2014 Interest income $ 129 $ 129 $ 246 Other nonoperating income 5 11 183 Insurance policy expense (43 ) (40 ) (488 ) Other nonoperating expense — (106 ) — Other income (expense), net $ 91 $ (6 ) $ (59 )

Fair Value of Financial Asset35

Fair Value of Financial Assets and Liabilities (Tables)	12 Months Ended
	Dec. 31, 2016
Fair Value Disclosures [Abstract]
Gross Notional Amounts of Commodity FTRs	The following table details the gross notional amounts of commodity FTRs at Dec. 31, 2016 and 2015: (Amounts in Thousands) (a) Dec. 31, 2016 Dec. 31, 2015 MWh of electricity 2,685 6,192 (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) 2016 2015 2014 Accumulated other comprehensive loss related to cash flow hedges at Jan. 1 $ (817 ) $ (989 ) $ (1,161 ) After-tax net realized losses on derivative transactions reclassified into earnings 139 172 172 Accumulated other comprehensive loss related to cash flow hedges at Dec. 31 $ (678 ) $ (817 ) $ (989 )
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 at Dec. 31, 2016: Dec. 31, 2016 Fair Value Fair Value Total Counterparty Netting (b) (Thousands of Dollars) Level 1 Level 2 Level 3 Total Current derivative assets Other derivative instruments: Electric commodity $ — $ — $ 3,254 $ 3,254 $ (1,299 ) $ 1,955 Total current derivative assets $ — $ — $ 3,254 $ 3,254 $ (1,299 ) 1,955 PPAs (a) 3,159 Current derivative instruments $ 5,114 Noncurrent derivative assets PPAs (a) $ 22,113 Noncurrent derivative instruments $ 22,113 Current derivative liabilities Other derivative instruments: Electric commodity $ — $ — $ 1,299 $ 1,299 $ (1,299 ) $ — Total current derivative liabilities $ — $ — $ 1,299 $ 1,299 $ (1,299 ) — PPAs (a) 3,565 Current derivative instruments $ 3,565 Noncurrent derivative liabilities PPAs (a) $ 23,513 Noncurrent derivative instruments $ 23,513 (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 balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Dec. 31, 2016. At Dec. 31, 2016, 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. 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 at Dec. 31, 2015: Dec. 31, 2015 Fair Value Fair Value Total Counterparty Netting (b) (Thousands of Dollars) Level 1 Level 2 Level 3 Total Current derivative assets Other derivative instruments: Electric commodity $ — $ — $ 8,980 $ 8,980 $ (3,920 ) $ 5,060 Total current derivative assets $ — $ — $ 8,980 $ 8,980 $ (3,920 ) 5,060 PPAs (a) 7,892 Current derivative instruments $ 12,952 Noncurrent derivative assets PPAs (a) $ 25,272 Noncurrent derivative instruments $ 25,272 Current derivative liabilities Other derivative instruments: Electric commodity $ — $ — $ 3,920 $ 3,920 $ (3,920 ) $ — Total current derivative liabilities $ — $ — $ 3,920 $ 3,920 $ (3,920 ) — PPAs (a) 3,565 Current derivative instruments $ 3,565 Noncurrent derivative liabilities PPAs (a) $ 27,078 Noncurrent derivative instruments $ 27,078 (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 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, 2015. At Dec. 31, 2015, 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 years ended Dec. 31, 2016, 2015 and 2014: Year Ended Dec. 31 (Thousands of Dollars) 2016 2015 2014 Balance at Jan. 1 $ 5,060 $ 15,884 $ 9,933 Purchases 7,616 23,425 50,244 Settlements (41,923 ) (31,703 ) (44,283 ) Net transactions recorded during the period: Gains (losses) recognized as regulatory assets 31,202 (2,546 ) (10 ) Balance at Dec. 31 $ 1,955 $ 5,060 $ 15,884
Carrying Amount and Fair Value of Long-term Debt	As of Dec. 31, 2016 and 2015, other financial instruments for which the carrying amount did not equal fair value were as follows: 2016 2015 (Thousands of Dollars) Carrying Amount Fair Value Carrying Amount Fair Value Long-term debt, including current portion (a) $ 1,635,858 $ 1,741,502 $ 1,538,522 $ 1,678,673

Rate Matters (Tables)

Rate Matters (Tables)	12 Months Ended
	Dec. 31, 2016
Public Utilities, General Disclosures [Abstract]
SPS' Texas 2016 Electric Rate Case	In December 2016, SPS reached an unopposed settlement that resolves all issues in the rate case. The following table reflects the total estimated impact: (Millions of Dollars) Settlement Base rate increase, retroactive to July 20, 2016 $ 35.2 Power factor revenues (a) 12.6 Rate case expenses to be addressed in a separate proceeding 4.0 Total estimated impact $ 51.8 (a) SPS’ request assumed customers would adjust their power factors, which would reduce revenue. To the extent power factor revenues are less than $12.6 million , a mechanism will be established to ensure SPS recovers this amount and effectively offset lower anticipated power factor charges.
SPS' New Mexico 2016 Electric Rate Case	The major components of the requested rate increase are summarized below: (Millions of Dollars) Request Capital expenditures $ 20.1 Allocator changes, including wholesale load reductions 11.5 Transmission expense, net of revenue, including charges paid to SPP for construction of regionally shared transmission projects 4.7 Depreciation, including adjustment of service life for the Tolk generating station 3.6 Rate case expenses 1.1 Other, net 0.4 Requested rate increase $ 41.4

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2016
Commitments and Contingencies Disclosure [Abstract]
Estimated Minimum Purchases Under Fuel Contracts	The estimated minimum purchases for SPS under these contracts as of Dec. 31, 2016 , are as follows: (Millions of Dollars) Coal Natural gas Natural gas 2017 $ 195.2 $ 16.7 $ 22.8 2018 — — 20.8 2019 — — 21.4 2020 — — 21.4 2021 — — 16.3 Thereafter — — 58.2 Total $ 195.2 $ 16.7 $ 160.9
Estimated Future Payments for Capacity and Energy Pursuant to Purchased Power Agreements	At Dec. 31, 2016 , 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) Capacity 2017 $ 58.0 2018 57.0 2019 19.4 2020 11.6 2021 11.9 Thereafter 29.7 Total $ 187.6
Future Commitments Under Operating Leases	Future commitments under operating leases are: (Millions of Dollars) Operating PPA (a) (b) Operating Leases Total 2017 $ 5.0 $ 51.5 $ 56.5 2018 5.7 50.7 56.4 2019 5.7 50.7 56.4 2020 5.6 50.7 56.3 2021 5.4 50.7 56.1 Thereafter 67.9 593.6 661.5 (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 for the years ended Dec. 31, 2016 and 2015 is as follows: (Thousands of Dollars) Beginning Balance Jan. 1, 2016 Accretion Cash Flow Revisions Ending Balance Dec. 31, 2016 (a) Electric plant Steam production asbestos $ 17,981 $ 1,089 $ — $ 19,070 Steam production ash containment 1,513 80 — 1,593 Electric distribution 6,559 240 — 6,799 Other 1,180 42 (21 ) 1,201 Total liability $ 27,233 $ 1,451 $ (21 ) $ 28,663 (a) There were no ARO liabilities recognized or settled during the year ended Dec. 31, 2016. (Thousands of Dollars) Beginning Balance Jan. 1, 2015 Accretion Cash Flow Revisions Ending Balance Dec. 31, 2015 (a) Electric plant Steam production asbestos $ 16,957 $ 1,024 $ — $ 17,981 Steam production ash containment 1,609 85 (181 ) 1,513 Electric distribution 6,327 232 — 6,559 Other 1,138 42 — 1,180 Total liability $ 26,031 $ 1,383 $ (181 ) $ 27,233 (a) There were no ARO liabilities recognized or settled during the year ended Dec. 31, 2015.

Regulatory Assets and Liabili38

Regulatory Assets and Liabilities (Tables)	12 Months Ended
	Dec. 31, 2016
Regulatory Assets and Liabilities Disclosure [Abstract]
Regulatory Assets	The components of regulatory assets shown on the balance sheets of SPS at Dec. 31, 2016 and 2015 are: (Thousands of Dollars) See Remaining Dec. 31, 2016 Dec. 31, 2015 Regulatory Assets Current Noncurrent Current Noncurrent Pension and retiree medical obligations (a) 7 Various $ 13,986 $ 234,171 $ 15,632 $ 223,122 Recoverable deferred taxes on AFUDC recorded in plant 1 Plant lives — 44,258 — 39,368 Net AROs (b) 11 Plant lives — 24,352 — 23,014 Renewable resources and environmental initiatives 11 One to four years 3,580 2,900 3,740 2,019 Conservation programs (c) 1 One to three years 3,754 2,431 5,137 3,859 Losses on reacquired debt 4 Term of related debt 127 1,617 850 1,743 Other Various 17,274 36,954 6,182 8,689 Total regulatory assets $ 38,721 $ 346,683 $ 31,541 $ 301,814 (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. 31, 2016 and 2015 are: (Thousands of Dollars) See Remaining Dec. 31, 2016 Dec. 31, 2015 Regulatory Liabilities Current Noncurrent Current Noncurrent Plant removal costs 11 Plant lives $ — $ 208,638 $ — $ 203,954 Revenue subject to refund 10 One to two years 5,093 3,602 20,647 1,080 Gain from asset sales 10 Various — 2,530 2,640 2,584 Deferred electric energy costs 1 Less than one year 32,451 — 61,041 — Contract valuation adjustments (a) 1, 9 Term of related contract 1,955 — 9,387 — Renewable resources and environmental initiatives 11 One to two years 1,075 — 2,960 880 Other Various 1,003 18,684 1,630 21,086 Total regulatory liabilities (b) $ 41,577 $ 233,454 $ 98,305 $ 229,584 (a) Includes the fair value of certain long-term PPAs used to meet energy capacity requirements. (b) Revenue subject to refund of $0 million and $3.9 million for 2016 and 2015, respectively, is included in other current liabilities.

Other Comprehensive Income (Tab

Other Comprehensive Income (Tables)	12 Months Ended
	Dec. 31, 2016
Stockholders' Equity Note [Abstract]
Changes in Accumulated Other Comprehensive Income (Loss), Net of Tax	Changes in accumulated other comprehensive loss, net of tax, for the years ended Dec. 31, 2016 and 2015 were as follows: Year Ended Dec. 31, 2016 (Thousands of Dollars) Gains and Losses on Cash Flow Hedges Defined Benefit Pension and Postretirement Items Total Accumulated other comprehensive loss at Jan. 1 $ (817 ) $ (464 ) $ (1,281 ) Other comprehensive loss before reclassifications — (148 ) (148 ) Losses reclassified from net accumulated other comprehensive loss 139 — 139 Net current period other comprehensive income (loss) 139 (148 ) (9 ) Accumulated other comprehensive loss at Dec. 31 $ (678 ) $ (612 ) $ (1,290 ) Year Ended Dec. 31, 2015 (Thousands of Dollars) Gains and Losses on Cash Flow Hedges Defined Benefit Pension and Postretirement Items Total Accumulated other comprehensive loss at Jan. 1 $ (989 ) $ — $ (989 ) Other comprehensive loss before reclassifications — (464 ) (464 ) Losses reclassified from net accumulated other comprehensive loss 172 — 172 Net current period other comprehensive income (loss) 172 (464 ) (292 ) Accumulated other comprehensive loss at Dec. 31 $ (817 ) $ (464 ) $ (1,281 )
Reclassifications out of Accumulated Other Comprehensive Loss	Reclassifications from accumulated other comprehensive loss for the years ended Dec. 31, 2016 and 2015 were as follows: Amounts Reclassified from Accumulated (Thousands of Dollars) Year Ended Dec. 31, 2016 Year Ended Dec. 31, 2015 Losses on cash flow hedges: Interest rate derivatives $ 219 (a) $ 269 (a) Total, pre-tax 219 269 Tax benefit (80 ) (97 ) Total amounts reclassified, net of tax $ 139 $ 172 (a) Included in interest charges.

Related Party Transactions (Tab

Related Party Transactions (Tables)	12 Months Ended
	Dec. 31, 2016
Related Party Transactions [Abstract]
Related Party Transactions	The table below contains significant affiliate transactions among the companies and related parties for the years ended Dec. 31: (Thousands of Dollars) 2016 2015 2014 Operating revenues: Electric $ 56 $ — $ 23 Operating expenses: Purchased power 8,809 8,632 9,614 Other operating expenses — paid to Xcel Energy Services Inc. 188,175 197,134 145,917 Interest expense 189 156 73 Interest income — 6 3 Accounts receivable and payable with affiliates at Dec. 31 were: 2016 2015 (Thousands of Dollars) Accounts Accounts Accounts Accounts NSP-Minnesota $ 935 $ — $ 1,066 $ — NSP-Wisconsin — 333 — 71 PSCo — 745 — 414 Other subsidiaries of Xcel Energy Inc. 14 13,336 13 28,650 $ 949 $ 14,414 $ 1,079 $ 29,135

Summarized Quarterly Financia41

Summarized Quarterly Financial Data (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2016
Quarterly Financial Information Disclosure [Abstract]
Summarized Quarterly Financial Data (Unaudited)	Quarter Ended (Thousands of Dollars) March 31, 2016 June 30, 2016 Sept. 30, 2016 Dec. 31, 2016 Operating revenues $ 390,839 $ 440,445 $ 554,926 $ 464,749 Operating income 53,569 68,386 122,362 62,964 Net income 22,523 32,211 68,346 29,077 Quarter Ended (Thousands of Dollars) March 31, 2015 June 30, 2015 Sept. 30, 2015 Dec. 31, 2015 Operating revenues $ 423,829 $ 422,985 $ 530,752 $ 409,652 Operating income 49,759 53,132 117,076 54,498 Net income 20,247 22,576 61,815 22,625

Summary of Significant Accoun42

Summary of Significant Accounting Policies (Details)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Conservation Programs [Abstract]
Maximum number of months following end of annual period in which revenues are earned to be included in incentive programs	24 months
Property, Plant and Equipment [Abstract]
Depreciation expense expressed as a percentage of average depreciable property	2.70%	2.60%	2.50%
Cash and Cash Equivalents [Abstract]
Maximum number of months of remaining maturity at time of purchase to consider investments in certain instruments as cash equivalents	3 months

Accounting Pronouncements Adopt

Accounting Pronouncements Adoption of New Accounting Pronouncements (Details) $ in Millions	Dec. 31, 2015USD ($)
Accounting Standards Update 2015-03 | Long-term Debt
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Reclassification of deferred debt issuance costs, net	$ 12.1
Accounting Standards Update 2015-03 | Other Noncurrent Assets
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Reclassification of deferred debt issuance costs, net	(12.1)
Accounting Standards Update 2015-17
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Deferred Income Tax Liabilities, Net	$ 35.7

Selected Balance Sheet Data (De

Selected Balance Sheet Data (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Accounts receivable, net
Accounts receivable	$ 80,569	$ 77,054
Less allowance for bad debts	(6,379)	(5,888)
Accounts receivable, net	$ 74,190	$ 71,166

Selected Balance Sheet Data Bal

Selected Balance Sheet Data Balance Sheet Related Disclosures, Inventories (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Public Utilities, Inventory [Line Items]
Inventories	$ 38,505	$ 37,546
Materials and supplies
Public Utilities, Inventory [Line Items]
Inventories	25,453	24,888
Fuel
Public Utilities, Inventory [Line Items]
Inventories	$ 13,052	$ 12,658

Selected Balance Sheet Data B46

Selected Balance Sheet Data Balance Sheet Related Disclosures, Property, Plant and Equipment (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Public Utility, Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	$ 6,622,516	$ 6,170,461
Less accumulated depreciation	(1,926,697)	(1,821,638)
Property, plant and equipment, net	4,695,819	4,348,823
Electric plant
Public Utility, Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	6,362,189	5,933,764
Construction work in progress
Public Utility, Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	$ 260,327	$ 236,697

Borrowings and Other Financin47

Borrowings and Other Financing Instruments, Short-Term Borrowings (Details) - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Short-term Debt [Line Items]
Amount outstanding at period end	$ 50,000	$ 50,000	$ 15,000
Money Pool
Short-term Debt [Line Items]
Borrowing limit	100,000	100,000	100,000	$ 100,000
Amount outstanding at period end	0	0	0	16,000
Average amount outstanding	20,000	28,000	21,000	9,000
Maximum amount outstanding	$ 64,000	$ 100,000	$ 100,000	$ 100,000
Weighted average interest rate, computed on a daily basis (percentage)	0.83%	0.67%	0.40%	0.22%
Weighted average interest rate at period end (percentage)				0.45%
Commercial Paper
Short-term Debt [Line Items]
Borrowing limit	$ 400,000	$ 400,000	$ 400,000	$ 400,000
Amount outstanding at period end	50,000	50,000	15,000	37,000
Average amount outstanding	19,000	43,000	100,000	83,000
Maximum amount outstanding	$ 75,000	$ 140,000	$ 246,000	$ 241,000
Weighted average interest rate, computed on a daily basis (percentage)	0.74%	0.67%	0.46%	0.26%
Weighted average interest rate at period end (percentage)	0.95%	0.95%	0.60%	0.47%

Borrowings and Other Financin48

Borrowings and Other Financing Instruments, Letters of Credit (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Line of Credit Facility [Line Items]
Amount outstanding at period end	$ 50,000	$ 15,000
Letter of Credit
Line of Credit Facility [Line Items]
Amount outstanding at period end	$ 5,000	$ 7,000
Letter of Credit | Letter of Credit
Line of Credit Facility [Line Items]
Term of letters of credit (in years)	1 year

Borrowings and Other Financin49

Borrowings and Other Financing Instruments, Credit Facility (Details) - Credit Facility		12 Months Ended
		Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)
Line of Credit Facility [Line Items]
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 (as a percent)		47.00%	46.00%
Line Of Credit Facility Minimum Threshhold Percentage Of Subsidiary Assets To Consolidated Assets Required To Initiate Cross Default Provisions		15.00%
Line of Credit Facility, Minimum Amount of Indebtedness in Default to Initiate Cross Default Provisions		$ 75,000,000
Credit facility	[1]	400,000,000
Drawn	[2]	55,000,000
Available		345,000,000
Direct advances on the credit outstanding		$ 0	$ 0
SPS
Line of Credit Facility [Line Items]
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
[1]	This credit facility matures in June 2021.
[2]	Includes outstanding commercial paper and letters of credit.

Borrowings and Other Financin50

Borrowings and Other Financing Instruments Borrowings and Other Financing Instruments, Amended Credit Agreements (Details) - Credit Facility	12 Months Ended
	Dec. 31, 2016USD ($)
Line of Credit Facility [Line Items]
Borrowing limit	$ 400,000,000	[1]
SPS
Line of Credit Facility [Line Items]
Debt Instrument, Term	5 years
Original Terms and Conditions [Member] | SPS
Line of Credit Facility [Line Items]
Line Of Credit Facility Minimum Borrowing Margin Based On Long Term Credit Ratings	0.875%
Line Of Credit Facility Maximum Borrowing Margin Based On Long Term Credit Ratings	1.75%
Maturity Date	Oct. 31, 2019
Line Of Credit Facility Minimum Commitment Fees Calculated On Unused Portion Of Lines Of Credit	0.075%
Line Of Credit Facility Maximum Commitment Fees Calculated On Unused Portion Of Lines Of Credit	0.275%
Amended Terms and Conditions [Member] | SPS
Line of Credit Facility [Line Items]
Line Of Credit Facility Minimum Borrowing Margin Based On Long Term Credit Ratings	0.75%
Line Of Credit Facility Maximum Borrowing Margin Based On Long Term Credit Ratings	1.50%
Maturity Date	Jun. 30, 2021
Line Of Credit Facility Minimum Commitment Fees Calculated On Unused Portion Of Lines Of Credit	0.06%
Line Of Credit Facility Maximum Commitment Fees Calculated On Unused Portion Of Lines Of Credit	0.225%
[1]	This credit facility matures in June 2021.

Borrowings and Other Financin51

Borrowings and Other Financing Instruments, Long-Term Borrowings (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Deferred Finance Costs, Noncurrent, Net	$ 14.5	$ 12.1
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)	54.10%
Unrestricted Retained Earnings Per State Regulatory Commissions Dividend Restrictions	$ 487
First Mortgage Bonds, Series due: | Series Due Aug. 15, 2046
Debt Instrument [Line Items]
Interest Rate, Stated Percentage (in hundredths)	3.40%	3.40%
Maturity Date	Aug. 15, 2046	Aug. 15, 2046
First Mortgage Bonds, Series due: | Series Due June 15, 2024
Debt Instrument [Line Items]
Interest Rate, Stated Percentage (in hundredths)	3.30%	3.30%
Maturity Date	Jun. 15, 2024	Jun. 15, 2024
Unsecured Debt [Member] | Senior G Due Dec. 1, 2018
Debt Instrument [Line Items]
Interest Rate, Stated Percentage (in hundredths)	8.75%	8.75%
Maturity Date	Dec. 1, 2018	Dec. 1, 2018
Long-term Debt, Maturities, Repayments of Principal in Year Two	$ 250
SPS | First Mortgage Bonds, Series due: | Series Due Aug. 15, 2046
Debt Instrument [Line Items]
Face Amount	$ 300
Interest Rate, Stated Percentage (in hundredths)	3.40%
Maturity Date	Aug. 15, 2046
SPS | First Mortgage Bonds, Series due: | Series Due June 15, 2024
Debt Instrument [Line Items]
Face Amount		$ 200
Interest Rate, Stated Percentage (in hundredths)		3.30%
Maturity Date		Jun. 15, 2024

Preferred Stock (Details)

Preferred Stock (Details)	Dec. 31, 2016$ / sharesshares
Equity [Abstract]
Preferred stock, shares authorized (in shares)	10,000,000
Preferred stock, par value (in dollars per share) | $ / shares	$ 1
Preferred stock, shares outstanding (in shares)	0

Income Taxes (Details)

Income Taxes (Details)	1 Months Ended	3 Months Ended	12 Months Ended
	Feb. 29, 2016	Sep. 30, 2015	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Dec. 31, 2012	Dec. 31, 2016USD ($)$ / kWh	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)
Consolidated Appropriations Act of 2016 [Abstract]
Excise Tax Delay			2 years
Unrecognized Tax Benefits, Interest on Income Taxes Accrued							$ (900,000)	$ 0	$ (100,000)	$ 0
Interest Income (Expense) related to unrecognized tax benefits			$ (900,000)	$ 100,000	$ (100,000)
Unrecognized Tax Benefits, Income Tax Penalties Accrued							0	0	0
Tax Increase Prevention Act of 2014 [Abstract]
Number of years bonus depreciation was extended					1 year
Unrecognized Tax Benefits [Abstract]
Unrecognized tax benefit — Permanent tax positions							4,500,000	2,600,000
Unrecognized tax benefit — Temporary tax positions							24,200,000	22,100,000
Total unrecognized tax benefit			24,700,000	13,200,000	$ 4,100,000		28,700,000	24,700,000	$ 13,200,000	$ 4,100,000
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Balance at Jan. 1			24,700,000	13,200,000	4,100,000
Unrecognized Tax Benefits, Increase Resulting from Current Period Tax Positions			1,400,000	4,200,000	8,600,000
Unrecognized Tax Benefits, Decrease Resulting from Current Period Tax Positions			0	(600,000)	0
Unrecognized Tax Benefits Increases Resulting From Prior Period Tax Positions			3,900,000	9,000,000	2,300,000
Unrecognized Tax Benefits Decreases Resulting From Prior Period Tax Positions			(1,300,000)	(1,100,000)	(300,000)
Unrecognized Tax Benefits, Decrease Resulting from Settlements with Taxing Authorities			0	0	(200,000)
Unrecognized Tax Benefits, Reduction Resulting from Lapse of Applicable Statute of Limitations			0	0	(1,300,000)
Balance at Dec. 31			$ 28,700,000	$ 24,700,000	$ 13,200,000
Tax Benefits Associated With NOL And Tax Credit Carryforwards [Abstract]
NOL and tax credit carryforwards							(5,900,000)	(5,000,000)
Decrease in Unrecognized Tax Benefits is Reasonably Possible							10,000,000
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			1.50%	2.60%	3.40%
Effective Income Tax Rate Reconciliation Change In Unrecognized Tax Benefits, Percent			0.80%	0.50%	0.20%
Effective Income Tax Rate Reconciliation Regulatory Differences Utility Plant Items, Percent			(1.00%)	(0.80%)	(1.60%)
Effective Income Tax Rate Reconciliation, Tax Credit, Percent			(0.50%)	(0.30%)	(0.40%)
Effective Income Tax Rate Reconciliation, Other Adjustments, Percent			(0.70%)	0.10%	0.10%
Effective Income Tax Rate Reconciliation, Percent			35.10%	37.10%	36.70%
Components of Income Tax Expense (Benefit), Continuing Operations [Abstract]
Current Federal Tax Expense (Benefit)			$ (40,853,000)	$ (1,327,000)	$ (57,201,000)
Current State and Local Tax Expense (Benefit)			(2,929,000)	2,448,000	2,512,000
Current Change In Unrecognized Tax Expense (Benefit)			3,126,000	11,281,000	6,715,000
Deferred Federal Income Tax Expense (Benefit)			116,404,000	67,640,000	121,882,000
Deferred State and Local Income Tax Expense (Benefit)			7,757,000	5,399,000	8,025,000
Deferred Change In Unrecognized Tax Expense (Benefit)			(1,178,000)	(10,203,000)	(6,390,000)
Deferred investment tax credits			(213,000)	(213,000)	(341,000)
Income Tax Expense (Benefit)			82,114,000	75,025,000	75,202,000
Deferred Income Tax Expense (Benefit), Continuing Operations [Abstract]
Deferred tax expense (benefit) excluding selected items			128,393,000	63,453,000	124,875,000
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities			(5,416,000)	(780,000)	(1,262,000)
Other Comprehensive Income (Loss), Tax			6,000	163,000	(96,000)
Deferred Income Tax Expense (Benefit)			122,983,000	$ 62,836,000	$ 123,517,000
Deferred Tax Liabilities, Gross [Abstract]
Deferred Tax Liabilities, Property, Plant and Equipment							1,034,675,000	945,142,000
Deferred Tax Liabilities, Compensation and Benefits, Employee Benefits							42,239,000	50,097,000
Deferred Tax Liabilities, Other							35,975,000	18,260,000
Deferred Tax Liabilities, Gross							1,112,889,000	1,013,499,000
Deferred Tax Assets, Gross [Abstract]
Deferred Tax Assets, Operating Loss Carryforwards							100,179,000	112,060,000
Deferred Tax Assets Unbilled Revenue Fuel Costs							10,226,000	23,127,000
Deferred Tax Assets Regulatory Liabilities							3,380,000	10,480,000
Deferred Tax Assets, Other							9,967,000	7,088,000
Deferred Tax Assets, Net of Valuation Allowance							123,752,000	152,755,000
Deferred Tax Liabilities, Net							989,137,000	860,744,000
Internal Revenue Service (IRS)
Tax Audits [Abstract]
Year(s) under examination		2012 and 2013				2010 and 2011
Year of carryback claim under examination						2,009
Potential Tax Adjustments			$ 14,000,000
Earliest year subject to examination			2,009
Operating Loss Carryforwards							275,000,000	306,000,000
Tax Credit Carryforward, Amount							4,000,000	3,000,000
Carryforward expiration date range, low			2,021
Carryforward expiration date range, high			2,036
State and Local Jurisdiction
Tax Audits [Abstract]
Earliest year subject to examination			2,009
Operating Loss Carryforwards							60,000,000	79,000,000
Valuation Allowance for Tax Credit Carryforward Net of Federal Benefit							$ 0	$ (11,000,000)
Carryforward expiration date range, low			2,017
Carryforward expiration date range, high			2,035
TEXAS
Tax Audits [Abstract]
Year(s) under examination	2009 and 2010
Consolidated Appropriations Act of 2016; 2015, 2016, 2017 Impact [Member]
Consolidated Appropriations Act of 2016 [Abstract]
Bonus depreciation rate, Percent							50.00%
Consolidated Appropriations Act of 2016; 2018 Impact [Member]
Consolidated Appropriations Act of 2016 [Abstract]
Bonus depreciation rate, Percent							40.00%
Production Tax Credit Rate, Percent							60.00%
Consolidated Appropriations Act of 2016; 2019 Impact [Member]
Consolidated Appropriations Act of 2016 [Abstract]
Bonus depreciation rate, Percent							30.00%
Production Tax Credit Rate, Percent							40.00%
Investment Tax Credit Rate, Percent							30.00%
Consolidated Appropriations Act of 2016; 2016 Impact [Member]
Consolidated Appropriations Act of 2016 [Abstract]
Production Tax Credit Rate, Percent							100.00%
Production Tax Credit per KWh | $ / kWh							0.023
Consolidated Appropriations Act of 2016; 2017 Impact [Member]
Consolidated Appropriations Act of 2016 [Abstract]
Production Tax Credit Rate, Percent							80.00%
Consolidated Appropriations Act of 2016; 2020 Impact [Member]
Consolidated Appropriations Act of 2016 [Abstract]
Investment Tax Credit Rate, Percent							26.00%
Consolidated Appropriations Act of 2016; 2021 Impact [Member]
Consolidated Appropriations Act of 2016 [Abstract]
Investment Tax Credit Rate, Percent							22.00%
Consolidated Appropriations Act of 2016; After 2021 Impact [Member]
Consolidated Appropriations Act of 2016 [Abstract]
Investment Tax Credit Rate, Percent							10.00%
Tax Increase Prevention Act of 2014; 2014 Impact [Member]
Consolidated Appropriations Act of 2016 [Abstract]
Bonus depreciation rate, Percent									50.00%
Tax Increase Prevention Act of 2014; 2015 Impact [Member]
Consolidated Appropriations Act of 2016 [Abstract]
Bonus depreciation rate, Percent							50.00%

Benefit Plans and Other Postr54

Benefit Plans and Other Postretirement Benefits, Employees Represented by Local Labor Unions (Details)	Dec. 31, 2016Employee
Employees Represented by Local Labor Unions Under Collective Bargaining Agreements Receiving Benefits [Abstract]
Approximate percent of employees receiving benefits who are represented by local labor unions under collective bargaining agreements (as a percent)	67.00%
Number of bargaining employees receiving benefits under several collective bargaining agreements	833

Benefit Plans and Other Postr55

Benefit Plans and Other Postretirement Benefits Benefit Plans and Other Postretirement Benefits, Fair Value Hierarchy (Details)	12 Months Ended
	Dec. 31, 2016
Commingled funds | Maximum
Defined Benefit Plan Disclosure [Line Items]
Notice period for investment redemption	90 days
Real estate funds | Minimum
Defined Benefit Plan Disclosure [Line Items]
Notice period for investment redemption	45 days
Real estate funds | Maximum
Defined Benefit Plan Disclosure [Line Items]
Notice period for investment redemption	90 days

Benefit Plans and Other Postr56

Benefit Plans and Other Postretirement Benefits, Pension Benefits (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Supplemental Executive Retirement Plan (SERP) and Nonqualified Pension Plan
Pension Benefits [Abstract]
Total benefit obligation	$ 2,500	$ 2,600
Net benefit cost recognized for financial reporting	$ 200	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	$ 483,601	467,394	$ 500,690
Net benefit cost recognized for financial reporting	$ 17,446	$ 20,303	$ 19,999
Expected average long-term rate of return on assets (as a percent)	6.78%	7.22%	6.90%
Expected average long-term rate of return on assets for next fiscal year (as a percent)	6.80%
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (as a percent)	100.00%	100.00%
Pension Plans | Domestic and international equity securities
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (as a percent)	36.00%	36.00%
Pension Plans | Long-duration fixed income and interest rate swap securities
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (as a percent)	31.00%	31.00%
Pension Plans | Short-to-intermediate fixed income securities
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (as a percent)	15.00%	12.00%
Pension Plans | Alternative investments
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (as a percent)	16.00%	19.00%
Pension Plans | Cash
Target Pension Asset Allocations [Abstract]
Target pension asset allocations (as a percent)	2.00%	2.00%
Xcel Energy Inc. | Supplemental Executive Retirement Plan (SERP) and Nonqualified Pension Plan
Pension Benefits [Abstract]
Total benefit obligation	$ 43,500	$ 41,800
Net benefit cost recognized for financial reporting	$ 7,900	$ 9,500

Benefit Plans and Other Postr57

Benefit Plans and Other Postretirement Benefits, Fair Value of Pension Plan Assets (Details) - Pension Plans - USD ($) $ in Thousands		Dec. 31, 2016		Dec. 31, 2015		Dec. 31, 2014
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		$ 380,395		$ 378,913		$ 402,269
Plan asset investments measured at net asset value		262,017	[1]	272,543	[2]
Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		39,714		36,491
Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		78,664		69,879
Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0		0
Cash equivalents
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		29,237		22,999
Plan asset investments measured at net asset value		0	[1]	0	[2]
Cash equivalents | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		29,237		22,999
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				553
Plan asset investments measured at net asset value	[2]			0
Derivatives | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets				0
Derivatives | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets				553
Derivatives | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets				0
U.S. equity funds
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		62,899		55,533
Plan asset investments measured at net asset value		62,899	[1]	55,533	[2]
U.S. equity funds | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0		0
U.S. equity funds | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0		0
U.S. equity funds | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0		0
Non U.S. equity funds
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		46,403		53,449
Plan asset investments measured at net asset value		46,403	[1]	53,449	[2]
Non U.S. equity funds | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0		0
Non U.S. equity funds | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0		0
Non U.S. equity funds | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0		0
U.S. corporate bond funds
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		41,226		32,020
Plan asset investments measured at net asset value		41,226	[1]	32,020	[2]
U.S. corporate bond funds | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0		0
U.S. corporate bond funds | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0		0
U.S. corporate bond funds | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0		0
Emerging market equity funds
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		24,637		23,891
Plan asset investments measured at net asset value		24,637	[1]	23,891	[2]
Emerging market equity funds | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0		0
Emerging market equity funds | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0		0
Emerging market equity funds | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0		0
Emerging market debt funds
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		20,399		23,169
Plan asset investments measured at net asset value		20,399	[1]	23,169	[2]
Emerging market debt funds | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0		0
Emerging market debt funds | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0		0
Emerging market debt funds | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0		0
Commodity funds
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		2,876		7,884
Plan asset investments measured at net asset value		2,876	[1]	7,884	[2]
Commodity funds | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0		0
Commodity funds | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0		0
Commodity funds | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0		0
Private equity investments
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		12,098		19,114
Plan asset investments measured at net asset value		12,098	[1]	19,114	[2]
Private equity investments | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0		0
Private equity investments | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0		0
Private equity investments | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0		0
Real estate
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		23,232		27,690
Plan asset investments measured at net asset value		23,232	[1]	27,690	[2]
Real estate | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0		0
Real estate | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0		0
Real estate | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0		0
Other commingled funds
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		28,247		29,793
Plan asset investments measured at net asset value		28,247	[1]	29,793	[2]
Other commingled funds | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0		0
Other commingled funds | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0		0
Other commingled funds | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0		0
Government securities
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		38,105		37,495
Plan asset investments measured at net asset value		0	[1]	0	[2]
Government securities | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0		0
Government securities | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		38,105		37,495
Government securities | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0		0
U.S. corporate bonds
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		36,293		28,826
Plan asset investments measured at net asset value		0	[1]	0	[2]
U.S. corporate bonds | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0		0
U.S. corporate bonds | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		36,293		28,826
U.S. corporate bonds | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0		0
Non U.S. corporate bonds
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		5,818		4,626
Plan asset investments measured at net asset value		0	[1]	0	[2]
Non U.S. corporate bonds | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0		0
Non U.S. corporate bonds | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		5,818		4,626
Non U.S. corporate bonds | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0		0
Mortgage-backed securities
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		821
Plan asset investments measured at net asset value	[1]	0
Mortgage-backed securities | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0
Mortgage-backed securities | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		821
Mortgage-backed securities | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0
Asset-backed securities
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		389		323
Plan asset investments measured at net asset value		0	[1]	0	[2]
Asset-backed securities | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0		0
Asset-backed securities | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		389		323
Asset-backed securities | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0		0
U.S. equities
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		10,477		13,492
Plan asset investments measured at net asset value		0	[1]	0	[2]
U.S. equities | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		10,477		13,492
U.S. equities | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0		0
U.S. equities | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0		0
Other
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		(2,762)		(1,944)
Plan asset investments measured at net asset value		0	[1]	0	[2]
Other | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0		0
Other | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		(2,762)		(1,944)
Other | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		$ 0		$ 0
[1]	Based on the requirements of ASU No. 2015-07, investments measured at fair value using a NAV methodology have not been classified in the fair value hierarchy. See Note 2 for further information on the adoption of ASU No. 2015-07.
[2]	Based on the requirements of ASU No. 2015-07, investments measured at fair value using a NAV methodology have not been classified in the fair value hierarchy. See Note 2 for further information on the adoption of ASU No. 2015-07.

Benefit Plans and Other Postr58

Benefit Plans and Other Postretirement Benefits, Pension Plan Benefit Obligations, Cash Flows and Benefit Costs (Details) $ in Thousands		1 Months Ended	12 Months Ended
		Jan. 31, 2017USD ($)	Dec. 31, 2016USD ($)Plan	Dec. 31, 2015USD ($)Plan	Dec. 31, 2014USD ($)Plan
Significant Assumptions Used to Measure Costs [Abstract]
Contributions to 401(k) and other defined contribution plans			$ 2,800	$ 2,600	$ 2,600
Pension Plans
Defined Benefit Plan Disclosure [Line Items]
Accumulated Benefit Obligation at Dec. 31			453,317	429,726
Change in Projected Benefit Obligation [Roll Forward]
Obligation at Jan. 1		$ 483,601	467,394	500,690
Service cost			9,761	11,006	9,184
Interest cost			21,259	20,184	20,444
Actuarial (gain) loss			25,053	(35,154)
Transfer (to) from other plan			(3,305)	(2,843)
Benefit payments			(36,561)	(26,489)
Obligation at Dec. 31			483,601	467,394	500,690
Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1		380,395	378,913	402,269
Actual return (loss) on plan assets			23,306	(6,013)
Employer contributions			18,088	11,651
Transfer (to) from other plan			(3,351)	(2,505)
Benefit payments			(36,561)	(26,489)
Fair value of plan assets at Dec. 31			380,395	378,913	402,269
Funded Status of Plans at Dec. 31 [Abstract]
Funded status	[1]		(103,206)	(88,481)
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost [Abstract]
Net loss			247,381	236,107
Total			247,381	236,107
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			13,524	13,690
Noncurrent regulatory assets			233,857	222,417
Total			$ 247,381	$ 236,107
Significant Assumptions Used to Measure Benefit Obligations [Abstract]
Discount rate for year-end valuation (as a percent)			4.13%	4.66%
Expected average long-term increase in compensation level (as a percent)			3.75%	4.00%
Mortality table			RP2014	RP2014
Cash Flows [Abstract]
Total contributions to Xcel Energy's pension plans during the period			$ 18,100	$ 11,700	4,900
Components of Net Periodic Benefit Cost (Credit) [Abstract]
Service cost			9,761	11,006	9,184
Interest cost			21,259	20,184	20,444
Expected return on plan assets			(27,602)	(28,610)	(26,179)
Amortization of prior service cost (credit)			0	39	54
Amortization of net (gain) loss			11,986	15,087	13,326
Net periodic pension cost			15,404	17,706	16,829
Defined Benefit Plan Credits (Costs) Not Recognized Due To Effects of Regulation			(2,042)	(2,597)	(3,170)
Net benefit cost recognized for financial reporting			$ 17,446	$ 20,303	$ 19,999
Significant Assumptions Used to Measure Costs [Abstract]
Discount rate (as a percent)			4.66%	4.11%	4.75%
Expected average long-term increase in compensation level (as a percent)			4.00%	3.75%	3.75%
Expected average long-term rate of return on assets (as a percent)			6.78%	7.22%	6.90%
Allocated costs for pension plans sponsored by Xcel Energy Services Inc.			$ 4,400	$ 4,800	$ 4,100
Expected average long-term rate of return on assets for next fiscal year (as a percent)			6.80%
Number of years fair market value of plan assets is adjusted using calculated value method (in years)			5 years
Annual adjustment rate used in calculated value method (as a percent)			20.00%
Xcel Energy Inc. | Pension Plans
Cash Flows [Abstract]
Total contributions to Xcel Energy's pension plans during the period			$ 125,200	$ 90,100	$ 130,600
Number of pension plans to which contributions were made | Plan			4	4	4
Subsequent Event | Pension Plans
Cash Flows [Abstract]
Total contributions to Xcel Energy's pension plans during the period		23,000
Subsequent Event | Xcel Energy Inc. | Pension Plans
Cash Flows [Abstract]
Total contributions to Xcel Energy's pension plans during the period		$ 150,000
[1]	Amounts are recognized in noncurrent liabilities on SPS’ balance sheets.

Benefit Plans and Other Postr59

Benefit Plans and Other Postretirement Benefits, Defined Contribution Plans (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Defined Contribution Plans [Abstract]
Contributions to 401(k) and other defined contribution plans	$ 2.8	$ 2.6	$ 2.6

Benefit Plans and Other Postr60

Benefit Plans and Other Postretirement Benefits, Postretirement Health Care Benefits (Details) - Postretirement Benefit Plan	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Postretirement Health Care Benefits [Abstract]
Target pension asset allocations (as a percent)	100.00%	100.00%
Domestic and international equity securities
Postretirement Health Care Benefits [Abstract]
Target pension asset allocations (as a percent)	25.00%	25.00%
Short-to-intermediate fixed income securities
Postretirement Health Care Benefits [Abstract]
Target pension asset allocations (as a percent)	57.00%	57.00%
Alternative investments
Postretirement Health Care Benefits [Abstract]
Target pension asset allocations (as a percent)	13.00%	13.00%
Cash
Postretirement Health Care Benefits [Abstract]
Target pension asset allocations (as a percent)	5.00%	5.00%

Benefit Plans and Other Postr61

Benefit Plans and Other Postretirement Benefits, Fair Value of Postretirement Benefit Plan Assets (Details) - Postretirement Benefit Plan - USD ($) $ in Thousands		Dec. 31, 2016		Dec. 31, 2015		Dec. 31, 2014
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		$ 42,297		$ 42,684		$ 45,356
Plan assets at net asset value		15,970	[1]	19,527	[2]
Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		5,885		1,873
Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		20,442		21,284
Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0		0
Cash equivalents
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		1,966		1,873
Plan assets at net asset value		0	[1]	0	[2]
Cash equivalents | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		1,966		1,873
Cash equivalents | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0		0
Cash equivalents | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0		0
Insurance contracts
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		4,519		4,501
Plan assets at net asset value		0	[1]	0	[2]
Insurance contracts | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0		0
Insurance contracts | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		4,519		4,501
Insurance contracts | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0		0
U.S. equity funds
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		5,208		3,643
Plan assets at net asset value		5,208	[1]	3,643	[2]
U.S. equity funds | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0		0
U.S. equity funds | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0		0
U.S. equity funds | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0		0
Non U.S. equity funds
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets				3,204
Plan assets at net asset value	[2]			3,204
Non U.S. equity funds | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets				0
Non U.S. equity funds | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets				0
Non U.S. equity funds | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets				0
U.S fixed income funds
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		2,593		2,311
Plan assets at net asset value		2,593	[1]	2,311	[2]
U.S fixed income funds | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0		0
U.S fixed income funds | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0		0
U.S fixed income funds | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0		0
Emerging market equity funds
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets				1,058
Plan assets at net asset value	[2]			1,058
Emerging market equity funds | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets				0
Emerging market equity funds | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets				0
Emerging market equity funds | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets				0
Emerging market debt funds
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		2,911		3,401
Plan assets at net asset value		2,911	[1]	3,401	[2]
Emerging market debt funds | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0		0
Emerging market debt funds | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0		0
Emerging market debt funds | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0		0
Other commingled funds
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		5,258		5,910
Plan assets at net asset value		5,258	[1]	5,910	[2]
Other commingled funds | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0		0
Other commingled funds | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0		0
Other commingled funds | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0		0
Government securities
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		3,611		3,742
Plan assets at net asset value		0	[1]	0	[2]
Government securities | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0		0
Government securities | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		3,611		3,742
Government securities | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0		0
U.S. corporate bonds
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		5,962		5,710
Plan assets at net asset value		0	[1]	0	[2]
U.S. corporate bonds | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0		0
U.S. corporate bonds | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		5,962		5,710
U.S. corporate bonds | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0		0
Non U.S. corporate bonds
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		1,653		1,239
Plan assets at net asset value		0	[1]	0	[2]
Non U.S. corporate bonds | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0		0
Non U.S. corporate bonds | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		1,653		1,239
Non U.S. corporate bonds | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0		0
Asset-backed securities
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		1,810		2,736
Plan assets at net asset value		0	[1]	0	[2]
Asset-backed securities | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0		0
Asset-backed securities | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		1,810		2,736
Asset-backed securities | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0		0
Mortgage-backed securities
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		2,748		3,396
Plan assets at net asset value		0	[1]	0	[2]
Mortgage-backed securities | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0		0
Mortgage-backed securities | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		2,748		3,396
Mortgage-backed securities | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0		0
Non U.S. equities
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		3,919
Plan assets at net asset value	[1]	0
Non U.S. equities | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		3,919
Non U.S. equities | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0
Non U.S. equities | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0
Other
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		139		(40)
Plan assets at net asset value		0	[1]	0	[2]
Other | Level 1
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		0		0
Other | Level 2
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		139		(40)
Other | Level 3
Plan Assets Measured at Fair Value for Each of the Fair Value Hierarchy Levels [Abstract]
Fair value of plan assets		$ 0		$ 0
[1]	Based on the requirements of ASU No. 2015-07, investments measured at fair value using a NAV methodology have not been classified in the fair value hierarchy. See Note 2 for further information on the adoption of ASU No. 2015-07.
[2]	Based on the requirements of ASU No. 2015-07, investments measured at fair value using a NAV methodology have not been classified in the fair value hierarchy. See Note 2 for further information on the adoption of ASU No. 2015-07.

Benefit Plans and Other Postr62

Benefit Plans and Other Postretirement Benefits, Postretirement Benefit Plan Benefit Obligations, Cash Flows and Benefit Costs (Details) - Postretirement Benefit Plan - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Change in Projected Benefit Obligation [Roll Forward]
Obligation at Jan. 1		$ 40,864	$ 44,342
Service cost		775	954	$ 1,246
Interest cost		1,821	1,745	2,572
Medicare subsidy reimbursements		31	45
Plan participants' contributions		653	687
Actuarial (gain) loss		1,293	(3,793)
Benefit payments		(3,577)	(3,116)
Obligation at Dec. 31		41,860	40,864	44,342
Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets at Jan. 1		42,684	45,356
Actual return (loss) on plan assets		1,978	(421)
Plan participants' contributions		653	687
Employer contributions		559	178
Benefit payments		(3,577)	(3,116)
Fair value of plan assets at Dec. 31		42,297	42,684	45,356
Funded Status of Plans at Dec. 31 [Abstract]
Funded status	[1]	437	1,820
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost (Credit) [Abstract]
Net loss		(12,595)	(14,870)
Prior service (credit) cost		(2,630)	(3,031)
Total		(15,225)	(17,901)
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost (Credit) Have Been Recorded as Follows Based Upon Expected Recovery in Rates [Abstract]
Current regulatory liabilities		(1,004)	(985)
Noncurrent regulatory liabilities		(14,221)	(16,916)
Total		$ (15,225)	$ (17,901)
Significant Assumptions Used to Measure Benefit Obligations [Abstract]
Discount rate for year-end valuation (as a percent)		4.13%	4.65%
Mortality table		RP 2,014	RP 2,014
Health care costs trend rate - initial (as a percent)		5.50%	6.00%
Ultimate health care trend assumption rate (as a percent)		4.50%
Period until ultimate trend rate is reached (in years)		2 years
Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rate [Abstract]
One-percent increase in APBO		$ 3,979
One-percent decrease in APBO		(3,389)
One-percent increase in service and interest components		273
One-percent decrease in service and interest components		(231)
Cash Flows [Abstract]
Total contributions to Xcel Energy's postretirement health care plans during the year		600	$ 200	200
Expected contribution to postretirement health care plans during 2017		0
Components of Net Periodic Benefit Cost (Credit) [Abstract]
Service cost		775	954	1,246
Interest cost		1,821	1,745	2,572
Expected return on plan assets		(2,377)	(2,540)	(3,247)
Amortization of prior service cost (credit)		(401)	(401)	(401)
Amortization of net (gain) loss		(583)	(639)	(321)
Net periodic pension cost		$ (765)	$ (881)	$ (151)
Significant Assumptions Used to Measure Costs [Abstract]
Discount rate (as a percent)		4.65%	4.08%	4.82%
Expected average long-term rate of return on assets (as a percent)		5.80%	5.80%	7.20%
Xcel Energy Inc.
Cash Flows [Abstract]
Total contributions to Xcel Energy's postretirement health care plans during the year		$ 17,900	$ 18,300	$ 17,100
Expected contribution to postretirement health care plans during 2017		$ 11,800
[1]	Amounts are recognized in noncurrent assets on SPS’ balance sheet as of Dec. 31, 2016 and 2015

Benefit Plans and Other Postr63

Benefit Plans and Other Postretirement Benefits, Projected Benefit Payments (Details) $ in Thousands	Dec. 31, 2016USD ($)
Pension Plans
Defined Benefit Plan, Gross Projected Benefit Payments [Abstract]
2,017	$ 28,596
2,018	28,086
2,019	28,545
2,020	29,567
2,021	29,716
2022-2026	156,673
Postretirement Benefit Plan
Defined Benefit Plan, Gross Projected Benefit Payments [Abstract]
2,017	3,420
2,018	3,203
2,019	3,008
2,020	3,015
2,021	3,096
2022-2026	14,135
Expected Medicare Part D Subsidies [Abstract]
2,017	24
2,018	26
2,019	24
2,020	25
2,021	26
2022-2026	148
Defined Benefit Plan, Net Projected Benefit Payments [Abstract]
2,017	3,396
2,018	3,177
2,019	2,984
2,020	2,990
2,021	3,070
2022-2026	$ 13,987

Other Income, Net (Details)

Other Income, Net (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Other Income and Expenses [Abstract]
Interest income	$ 129	$ 129	$ 246
Other nonoperating income	5	11	183
Insurance Policy Expense (Income), Net	(43)	(40)	(488)
Other Nonoperating Expense	0	(106)	0
Other income (expense), net	$ 91	$ (6)	$ (59)

Fair Value of Financial Asset65

Fair Value of Financial Assets and Liabilities, Derivative Instruments (Details) MWh in Thousands, $ in Millions		Dec. 31, 2016USD ($)MWhCounterparty	Dec. 31, 2015MWh
Credit Concentration Risk
Consideration of Credit Risk and Concentrations [Abstract]
Number of most significant counterparties for wholesale activities with credit exposure		8
Credit Concentration Risk | Municipal or Cooperative Entities or Other Utilities [Member]
Consideration of Credit Risk and Concentrations [Abstract]
Number of most significant counterparties for wholesale activities with credit exposure		7
Credit Concentration Risk | No Investment Grade Ratings from External Credit Rating Agencies [Member]
Consideration of Credit Risk and Concentrations [Abstract]
Number of most significant counterparties for wholesale activities with credit exposure		7
Wholesale, trading and non-trading commodity credit exposure for the most significant counterparties | $		$ 50
Percentage of wholesale, trading and non-trading commodity credit exposure for the most significant counterparties (in hundredths)		56.00%
Credit Concentration Risk | Credit Quality Less Than Investment Grade [Member]
Consideration of Credit Risk and Concentrations [Abstract]
Number of most significant counterparties for wholesale activities with credit exposure		1
Wholesale, trading and non-trading commodity credit exposure for the most significant counterparties | $		$ 1.9
Percentage of wholesale, trading and non-trading commodity credit exposure for the most significant counterparties (in hundredths)		2.00%
Interest Rate Swap
Interest Rate Derivatives [Abstract]
Amount of accumulated other comprehensive gains (losses) related to interest rate derivatives expected to be reclassified into earnings within the next twelve months | $		$ (0.1)
Electric Commodity (in megawatt hours)
Gross Notional Amounts of Commodity Forwards, Options and FTRs [Abstract]
Derivative, Nonmonetary Notional Amount | MWh	[1]	2,685	6,192
[1]	Amounts are not reflective of net positions in the underlying commodities.

Fair Value of Financial Asset66

Fair Value of Financial Assets and Liabilities, Financial Impact of Qualifying Cash Flow Hedges (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Financial Impact of Qualifying Cash Flow Hedges on Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Accumulated other comprehensive loss related to cash flow hedges at Jan. 1	$ (817)	$ (989)	$ (1,161)
After-tax net realized losses on derivative transactions reclassified into earnings	139	172	172
Accumulated other comprehensive loss related to cash flow hedges at Dec. 31	$ (678)	$ (817)	$ (989)

Fair Value of Financial Asset67

Fair Value of Financial Assets and Liabilities, Impact of Derivative Activity (Details) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Financial Impact of Qualifying Fair Value Hedges on Earnings [Abstract]
Derivative instruments designated as fair value hedges	$ 0	$ 0	$ 0
Recognized gains (losses) from fair value hedges or related hedged transactions	0	0	0
Designated as Hedging Instrument | Cash Flow Hedges | Interest Rate
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract]
Interest Rate Cash Flow Hedge Gain (Loss) Reclassified to Earnings, Net	(200,000)	(300,000)	(300,000)
Other Derivative Instruments | Electric Commodity
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract]
Pre-tax fair value gains (losses) recognized during the period in regulatory (assets) and liabilities	3,000,000	(3,100,000)	(3,900,000)
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities)	$ (2,100,000)	$ 1,600,000	$ 8,200,000

Fair Value of Financial Asset68

Fair Value of Financial Assets and Liabilities, Derivative Assets and Liabilities at Fair Value (Details) - USD ($)	Dec. 31, 2016		Dec. 31, 2015
Derivatives, Fair Value [Line Items]
Derivative Asset, Collateral, Obligation to Return Cash, Offset	$ 0		$ 0
Derivative Liability, Collateral, Right to Reclaim Cash, Offset	0		0
Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	5,114,000		12,952,000
Other Noncurrent Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	22,113,000		25,272,000
Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	3,565,000		3,565,000
Other Noncurrent Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	23,513,000		27,078,000
Fair Value Measured on a Recurring Basis | Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	1,955,000		5,060,000
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset	(1,299,000)	[1]	(3,920,000)	[2]
Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	1,955,000		5,060,000
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset	(1,299,000)	[1]	(3,920,000)	[2]
Fair Value Measured on a Recurring Basis | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	0		0
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset	(1,299,000)	[1]	(3,920,000)	[2]
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	0		0
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset	(1,299,000)	[1]	(3,920,000)	[2]
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0		0
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Assets | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0		0
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	0		0
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Liabilities | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	0		0
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0		0
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Assets | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0		0
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	0		0
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Liabilities | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	0		0
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	3,254,000		8,980,000
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Assets | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	3,254,000		8,980,000
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	1,299,000		3,920,000
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Liabilities | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	1,299,000		3,920,000
Fair Value, Measurements, Nonrecurring | Other Current Assets | Purchased Power Agreements
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	3,159,000	[3]	7,892,000	[4]
Fair Value, Measurements, Nonrecurring | Other Noncurrent Assets | Purchased Power Agreements
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	22,113,000	[3]	25,272,000	[4]
Fair Value, Measurements, Nonrecurring | Other Current Liabilities | Purchased Power Agreements
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	3,565,000	[3]	3,565,000	[4]
Fair Value, Measurements, Nonrecurring | Other Noncurrent Liabilities | Purchased Power Agreements
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	23,513,000	[3]	27,078,000	[4]
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	3,254,000		8,980,000
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	3,254,000		8,980,000
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	1,299,000		3,920,000
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	$ 1,299,000		$ 3,920,000
[1]	SPS nets derivative instruments and related collateral in its balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Dec. 31, 2016. At Dec. 31, 2016, 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]	SPS nets derivative instruments and related collateral in its 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, 2015. At Dec. 31, 2015, 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.
[3]	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.
[4]	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 Asset69

Fair Value of Financial Assets and Liabilities, Changes in Level 3 Commodity Derivatives (Details) (Details) - Commodity Contract - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Balance at beginning of period	$ 5,060,000	$ 15,884,000	$ 9,933,000
Purchases	7,616,000	23,425,000	50,244,000
Settlements	(41,923,000)	(31,703,000)	(44,283,000)
Gains (losses) recognized as regulatory assets	31,202,000	(2,546,000)	(10,000)
Balance at end of period	1,955,000	5,060,000	15,884,000
Level 3 transfers, net	$ 0	$ 0	$ 0

Fair Value of Financial Asset70

Fair Value of Financial Assets and Liabilities, Fair Value of Long-Term Debt (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Carrying Amount
Financial Liabilities, Balance Sheet Groupings [Abstract]
Long-term debt, including current portion	$ 1,635,858	$ 1,538,522
Fair Value
Financial Liabilities, Balance Sheet Groupings [Abstract]
Long-term debt, including current portion	$ 1,741,502	$ 1,678,673

Rate Matters (Details)

Rate Matters (Details) $ in Millions		1 Months Ended					12 Months Ended
		Feb. 28, 2017USD ($)	Dec. 31, 2016USD ($)	Nov. 30, 2016USD ($)MW	Sep. 30, 2016USD ($)	Feb. 29, 2016USD ($)	Dec. 31, 2016	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Appeal of the Texas 2015 Electric Rate Case Decision
Rate Matters [Abstract]
Public Utilities, Requested Rate Increase (Decrease), Amount									$ 64.8
Public Utilities, Revised Requested Rate Increase									$ 42.1
PUCT Proceeding - Texas 2016 Electric Rate Case
Rate Matters [Abstract]
Public Utilities, Requested Rate Increase (Decrease), Amount						$ 71.9
Public Utilities, Revised Requested Rate Increase					$ 61.5
Public Utilities, Requested Rate Increase (Decrease), Percentage						14.40%
Public Utilities, Requested Return on Equity, Percentage						10.25%
Public Utilities, Requested Rate Base, Amount						$ 1,700
Public Utilities, Requested Equity Capital Structure, Percentage						53.97%
Public Utilities, Revised Requested Rate Increase, Including Rate Case Expenses					$ 65.5
Public Utilities, Base Rate Increase Under the Stipulation			$ 35.2
Public Utilities, Mechanism Ensuring Recover in Revenues from Power Factor Charge	[1]		12.6
Public Utilities, Rate Case Expenses Addressed in Separate Proceeding			4
Public Utilities, Total Estimated Impact of Stipulation			51.8
Public Utilities, Additional Revenue Cap in Future TCRF Application Under the Stipulation			$ 19
Public Utilities, Number of Days for PUCT Approval of the Next Transmission Cost Recovery Factor Application Under the Stipulation			100 days
NMPRC Proceeding - New Mexico 2016 Electric Rate Case
Rate Matters [Abstract]
Public Utilities, Requested Rate Increase (Decrease), Amount				$ 41.4
Public Utilities, Requested Rate Increase (Decrease), Percentage				10.90%
Public Utilities, Requested Return on Equity, Percentage				10.10%
Public Utilities, Requested Rate Base, Amount				$ 832
Public Utilities, Requested Equity Capital Structure, Percentage				53.97%
Public Utilities, Future Decline in MW Sales from Certain Wholesale Customers included in Rate Case | MW				380
Public Utilities, Capital Expenditures				$ 20.1
Public Utilities, Changes in Allocator, Including Wholesale Load Reductions				11.5
Public Utilities, Transmission Expenses				4.7
Public Utilities, Depreciation, Including Adjustment of Tolk Service Life				3.6
Public Utilities, Rate Case Expenses				1.1
Public Utilities, Other net				0.4
SPP Open Access Transmission Tariff Upgrade Costs
Rate Matters [Abstract]
Public Utilities, Billed Charges For Transmission Service Upgrades				$ 12.8
Public Utility Commission of Texas (PUCT) | Appeal of the Texas 2015 Electric Rate Case Decision
Rate Matters [Abstract]
Public Utilities, Approved Rate Decrease, Net of Rate Case Expenses								$ 4
Southwest Power Pool (SPP) | SPP Open Access Transmission Tariff Upgrade Costs
Rate Matters [Abstract]
Public Utilities, Length of Payment Period Requested, In Years							5 years
Subsequent Event | Texas 2016 TCRF Application [Member]
Rate Matters [Abstract]
Public Utilities, Requested Rate Increase (Decrease), Amount		$ 16.1
Public Utilities, Requested Rate Increase (Decrease), Percentage		1.79%
[1]	(a) SPS’ request assumed customers would adjust their power factors, which would reduce revenue. To the extent power factor revenues are less than $12.6 million, a mechanism will be established to ensure SPS recovers this amount and effectively offset lower anticipated power factor charges.

Commitments and Contingencies,

Commitments and Contingencies, Capital Commitments (Details) - Capital Commitments	12 Months Ended
	Dec. 31, 2016kV
TUCO to Yoakum to Hobbs Plant Transmission Line
Capital Commitments [Abstract]
Voltage capacity for transmission line (in kV)	345
Hobbs Plant to China Draw Transmission Line
Capital Commitments [Abstract]
Voltage capacity for transmission line (in kV)	345

Commitments and Contingencies73

Commitments and Contingencies, Fuel Contracts (Details) $ in Millions	12 Months Ended
	Dec. 31, 2016USD ($)
Coal
Fuel Contracts [Abstract]
2,017	$ 195.2
2,018	0
2,019	0
2,020	0
2,021	0
Thereafter	0
Total	195.2
Natural Gas Supply
Fuel Contracts [Abstract]
2,017	16.7
2,018	0
2,019	0
2,020	0
2,021	0
Thereafter	0
Total	16.7
Natural Gas Storage and Transportation
Fuel Contracts [Abstract]
2,017	22.8
2,018	20.8
2,019	21.4
2,020	21.4
2,021	16.3
Thereafter	58.2
Total	$ 160.9
Minimum
Unrecorded Unconditional Purchase Obligation [Line Items]
Fuel Contract Expiration Date	2,017
Maximum
Unrecorded Unconditional Purchase Obligation [Line Items]
Fuel Contract Expiration Date	2,033

Commitments and Contingencies74

Commitments and Contingencies, Purchased Power Agreements (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Long-term Contract for Purchase of Electric Power [Line Items]
Purchase Power Agreement Expiration Date	2,033
Capacity
Purchased Power Agreements (PPAs) [Abstract]
Payments for capacity	$ 56.8	$ 56.7	$ 52.4
Estimated Future Payments Under PPAs [Abstract]
2,017	58
2,018	57
2,019	19.4
2,020	11.6
2,021	11.9
Thereafter	29.7
Total	$ 187.6

Commitments and Contingencies75

Commitments and Contingencies, Leases (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Operating Leased Assets [Line Items]
Operating Lease Purchase Power Agreement Expiration Date		2,033
Operating Leases, Future Minimum Payments Due [Abstract]
2,017		$ 56.5
2,018		56.4
2,019		56.4
2,020		56.3
2,021		56.1
Thereafter		661.5
Office Space and Other Equipment
Operating Leases [Abstract]
Total expenses under operating lease obligations		56.6	$ 54.5	$ 63.1
Operating Leases, Future Minimum Payments Due [Abstract]
2,017		5
2,018		5.7
2,019		5.7
2,020		5.6
2,021		5.4
Thereafter		67.9
Purchased Power Agreements
Operating Leases [Abstract]
Payments for capacity for PPAs under operating lease obligations		50.6	$ 48.6	$ 57.1
Operating Leases, Future Minimum Payments Due [Abstract]
2,017	[1],[2]	51.5
2,018	[1],[2]	50.7
2,019	[1],[2]	50.7
2,020	[1],[2]	50.7
2,021	[1],[2]	50.7
Thereafter	[1],[2]	$ 593.6
[1]	Amounts do not include PPAs accounted for as executory contracts.
[2]	PPA operating leases contractually expire through 2033.

Commitments and Contingencies76

Commitments and Contingencies, Variable Interest Entities (Details) - MW	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Purchased Power Agreements [Abstract]
VIE Purchase Power Agreement Expiration Date	2,041
Independent Power Producing Entities
Purchased Power Agreements [Abstract]
Generating capacity (in MW)	897	827
Harrington Station Power Plant
Fuel Contracts [Abstract]
Coal Supply Agreement Expiration Date	2,017
Tolk Station Power Plant
Fuel Contracts [Abstract]
Coal Supply Agreement Expiration Date	2,017

Commitments and Contingencies77

Commitments and Contingencies, Environmental Contingencies (Details) $ in Millions	1 Months Ended	12 Months Ended
	Sep. 30, 2016	Dec. 31, 2016USD ($)	Dec. 31, 2015Period
Cross-State Air Pollution Rule (CSAPR)
Environmental Requirements [Abstract]
Adopted Reduction Related to the Ozone Season Emission Budget for NOx	22.00%
Implementation of the National Ambient Air Quality Standard for Sulfur Dioxide
Environmental Requirements [Abstract]
Number of Phases Under a Consent Decree Which the EPA is Requiring States to Evaluate Areas for Attainment		3
National Ambient Air Quality Standards for Ozone
Environmental Requirements [Abstract]
Number of Hours Measured for Standard | Period			8
Former Level of Air Quality Concentrations (in parts per billion)			75
Revised Level of Air Quality Concentrations (in parts per billion)		70	70
Harrington Units 1 and 2 | Implementation of the National Ambient Air Quality Standard for Sulfur Dioxide
Environmental Requirements [Abstract]
Number of Years Unclassifiable Areas Will Be Monitored		3 years
Harrington Units 1 and 2 | Capital Commitments | Regional Haze Rules
Environmental Requirements [Abstract]
Liability for Estimated Cost to Comply with Regulation		$ 400
Tolk Units 1 and 2 | Capital Commitments | Regional Haze Rules
Environmental Requirements [Abstract]
Liability for Estimated Cost to Comply with Regulation		$ 600

Commitments and Contingencies78

Commitments and Contingencies, Asset Retirement Obligations (Details) - USD ($)	12 Months Ended
	Dec. 31, 2016		Dec. 31, 2015
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	$ 27,233,000	[1]	$ 26,031,000
Liabilities Incurred	0		0
Liabilities settled	0		0
Accretion	1,451,000		1,383,000
Cash flow revisions	(21,000)		(181,000)
Ending balance	28,663,000	[2]	27,233,000	[1]
Electric Plant Steam Production Asbestos
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	17,981,000	[1]	16,957,000
Liabilities Incurred	0		0
Liabilities settled	0		0
Accretion	1,089,000		1,024,000
Cash flow revisions	0		0
Ending balance	19,070,000	[2]	17,981,000	[1]
Electric Plant Steam Production Ash Containment
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	1,513,000	[1]	1,609,000
Liabilities Incurred	0		0
Liabilities settled	0		0
Accretion	80,000		85,000
Cash flow revisions	0		(181,000)
Ending balance	1,593,000	[2]	1,513,000	[1]
Electric Plant Electric Distribution
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	6,559,000	[1]	6,327,000
Liabilities Incurred	0		0
Liabilities settled	0		0
Accretion	240,000		232,000
Cash flow revisions	0		0
Ending balance	6,799,000	[2]	6,559,000	[1]
Electric Plant Other
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	1,180,000	[1]	1,138,000
Liabilities Incurred	0		0
Liabilities settled	0		0
Accretion	42,000		42,000
Cash flow revisions	(21,000)		0
Ending balance	$ 1,201,000	[2]	$ 1,180,000	[1]
[1]	(a) There were no ARO liabilities recognized or settled during the year ended Dec. 31, 2015.
[2]	(a) There were no ARO liabilities recognized or settled during the year ended Dec. 31, 2016.

Commitments and Contingencies79

Commitments and Contingencies, Removal Costs (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Plant Removal Costs
Regulatory Liabilities [Line Items]
Regulatory Liabilities	$ 209	$ 204

Regulatory Assets and Liabili80

Regulatory Assets and Liabilities, Regulatory Assets (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015
Regulatory Assets [Line Items]
Regulatory Asset, Current		$ 38,721	$ 31,541
Regulatory Asset, Noncurrent		346,683	301,814
Past expenditures not currently earning a return		$ 65,000	25,000
Pension and Retiree Medical Obligations
Regulatory Assets [Line Items]
Regulatory asset, remaining amortization period		Various
Regulatory Asset, Current	[1]	$ 13,986	15,632
Regulatory Asset, Noncurrent	[1]	$ 234,171	223,122
Recoverable Deferred Taxes on AFUDC Recorded in Plant
Regulatory Assets [Line Items]
Regulatory asset, remaining amortization period		Plant lives
Regulatory Asset, Current		$ 0	0
Regulatory Asset, Noncurrent		$ 44,258	39,368
Net AROs
Regulatory Assets [Line Items]
Regulatory asset, remaining amortization period		Plant lives
Regulatory Asset, Current	[2]	$ 0	0
Regulatory Asset, Noncurrent	[2]	$ 24,352	23,014
Renewable Resources and Environmental Initiatives
Regulatory Assets [Line Items]
Regulatory asset, remaining amortization period		One to four years
Regulatory Asset, Current		$ 3,580	3,740
Regulatory Asset, Noncurrent		$ 2,900	2,019
Conservation Programs
Regulatory Assets [Line Items]
Regulatory asset, remaining amortization period		One to three years
Regulatory Asset, Current	[3]	$ 3,754	5,137
Regulatory Asset, Noncurrent	[3]	$ 2,431	3,859
Losses on Reacquired Debt
Regulatory Assets [Line Items]
Regulatory asset, remaining amortization period		Term of related debt
Regulatory Asset, Current		$ 127	850
Regulatory Asset, Noncurrent		$ 1,617	1,743
Other Regulatory Assets
Regulatory Assets [Line Items]
Regulatory asset, remaining amortization period		Various
Regulatory Asset, Current		$ 17,274	6,182
Regulatory Asset, Noncurrent		$ 36,954	$ 8,689
[1]	(a) Includes the non-qualified pension plan.
[2]	(b) Includes amounts recorded for future recovery of AROs.
[3]	(c) Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions.

Regulatory Assets and Liabili81

Regulatory Assets and Liabilities, Regulatory Liabilities (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015
Regulatory Liabilities [Line Items]
Regulatory Liability, Current	[1]	$ 41,577	$ 98,305
Regulatory Liability, Noncurrent		$ 233,454	229,584
Plant Removal Costs
Regulatory Liabilities [Line Items]
Regulatory liability, remaining amortization period		Plant lives
Regulatory Liability, Current		$ 0	0
Regulatory Liability, Noncurrent		$ 208,638	203,954
Revenue Subject to Refund
Regulatory Liabilities [Line Items]
Regulatory liability, remaining amortization period		One to two years
Regulatory Liability, Current		$ 5,093	20,647
Regulatory Liability, Noncurrent		$ 3,602	1,080
Gain From Asset Sales
Regulatory Liabilities [Line Items]
Regulatory liability, remaining amortization period		Various
Regulatory Liability, Current		$ 0	2,640
Regulatory Liability, Noncurrent		$ 2,530	2,584
Deferred Electric Energy Costs
Regulatory Liabilities [Line Items]
Regulatory liability, remaining amortization period		Less than one year
Regulatory Liability, Current		$ 32,451	61,041
Regulatory Liability, Noncurrent		$ 0	0
Contract Valuation Adjustments
Regulatory Liabilities [Line Items]
Regulatory liability, remaining amortization period		Term of related contract
Regulatory Liability, Current	[2]	$ 1,955	9,387
Regulatory Liability, Noncurrent	[2]	$ 0	0
Renewable Resources and Environmental Initiatives
Regulatory Liabilities [Line Items]
Regulatory liability, remaining amortization period		One to two years
Regulatory Liability, Current		$ 1,075	2,960
Regulatory Liability, Noncurrent		$ 0	880
Other Regulatory Liabilities
Regulatory Liabilities [Line Items]
Regulatory liability, remaining amortization period		Various
Regulatory Liability, Current		$ 1,003	1,630
Regulatory Liability, Noncurrent		18,684	21,086
Other Current Liabilities
Regulatory Liabilities [Line Items]
Entity's Recorded Provision for Revenue Subject To Refund		$ 0	$ 3,900
[1]	(b) Revenue subject to refund of $0 million and $3.9 million for 2016 and 2015, respectively, is included in other current liabilities.
[2]	(a) Includes the fair value of certain long-term PPAs used to meet energy capacity requirements.

Other Comprehensive Income (Det

Other Comprehensive Income (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Accumulated other comprehensive loss at beginning of period		$ 1,807,949
Accumulated other comprehensive loss at end of period		1,931,696	$ 1,807,949
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Total, pre-tax		(234,271)	(202,288)	$ (205,054)
Tax benefit		82,114	75,025	75,202
AOCI Attributable to Parent
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Accumulated other comprehensive loss at beginning of period		(1,281)	(989)
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax		(148)	(464)
(Gains) losses reclassified from net accumulated other comprehensive loss		139	172
Net current period other comprehensive income (loss)		(9)	(292)
Accumulated other comprehensive loss at end of period		(1,290)	(1,281)	(989)
Accumulated Defined Benefit Plans Adjustment Attributable to Parent [Member]
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Accumulated other comprehensive loss at beginning of period		(464)	0
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax		(148)	(464)
(Gains) losses reclassified from net accumulated other comprehensive loss		0	0
Net current period other comprehensive income (loss)		(148)	(464)
Accumulated other comprehensive loss at end of period		(612)	(464)	0
Gains and Losses on Cash Flow Hedges
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Accumulated other comprehensive loss at beginning of period		(817)	(989)
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax		0	0
(Gains) losses reclassified from net accumulated other comprehensive loss		139	172
Net current period other comprehensive income (loss)		139	172
Accumulated other comprehensive loss at end of period		(678)	(817)	$ (989)
Gains and Losses on Cash Flow Hedges | Amounts Reclassified from Accumulated Other Comprehensive Loss
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Total, pre-tax		219	269
Tax benefit		(80)	(97)
Total, net of tax		139	172
Gains and Losses on Cash Flow Hedges | Interest Rate Derivatives | Amounts Reclassified from Accumulated Other Comprehensive Loss
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Interest charges	[1]	$ 219	$ 269
[1]	(a) Included in interest charges.

Related Party Transactions (Det

Related Party Transactions (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Operating revenues [Abstract]
Electric	$ 56	$ 0	$ 23
Operating expenses [Abstract]
Purchased power	8,809	8,632	9,614
Other operating expenses - paid to Xcel Energy Services Inc.	188,175	197,134	145,917
Interest expense	189	156	73
Interest income	0	6	$ 3
Accounts Receivable and Payable with Affiliates [Abstract]
Accounts receivable	949	1,079
Accounts payable	14,414	29,135
NSP-Minnesota
Accounts Receivable and Payable with Affiliates [Abstract]
Accounts receivable	935	1,066
Accounts payable	0	0
NSP-Wisconsin
Accounts Receivable and Payable with Affiliates [Abstract]
Accounts receivable	0	0
Accounts payable	333	71
PSCo
Accounts Receivable and Payable with Affiliates [Abstract]
Accounts receivable	0	0
Accounts payable	745	414
Other Subsidiaries of Xcel Energy Inc.
Accounts Receivable and Payable with Affiliates [Abstract]
Accounts receivable	14	13
Accounts payable	$ 13,336	$ 28,650

Summarized Quarterly Financia84

Summarized Quarterly Financial Data (Unaudited) (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Quarterly Financial Information Disclosure [Abstract]
Operating revenues	$ 464,749	$ 554,926	$ 440,445	$ 390,839	$ 409,652	$ 530,752	$ 422,985	$ 423,829
Operating income	62,964	122,362	68,386	53,569	54,498	117,076	53,132	49,759	$ 307,281	$ 274,465	$ 266,124
Net income	$ 29,077	$ 68,346	$ 32,211	$ 22,523	$ 22,625	$ 61,815	$ 22,576	$ 20,247	$ 152,157	$ 127,263	$ 129,852

Schedule II, Valuation and Qu85

Schedule II, Valuation and Qualifying Accounts (Details) - Allowance for Bad Debts - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Movement in Valuation Allowances and Reserves [Roll Forward]
Balance at Jan. 1		$ 5,888	$ 5,839	$ 5,475
Charged to costs and expenses		6,066	4,655	4,137
Charged to other accounts	[1]	907	1,036	1,089
Deductions from reserves	[2]	6,482	5,642	4,862
Balance at Dec. 31		$ 6,379	$ 5,888	$ 5,839
[1]	Recovery of amounts previously written off.
[2]	Deductions relate primarily to bad debt write-offs.