Southwestern Public Service 10-Q 2 Nov 15 2015 Q3 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2015	Nov. 02, 2015
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-Q
Document Period End Date	Sep. 30, 2015
Document Fiscal Year Focus	2,015
Document Fiscal Period Focus	Q3
Amendment Flag	false
Entity Common Stock, Shares Outstanding		100

STATEMENTS OF INCOME (UNAUDITED

STATEMENTS OF INCOME (UNAUDITED) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Income Statement [Abstract]
Operating revenues	$ 530,752	$ 552,779	$ 1,377,566	$ 1,493,715
Operating expenses
Electric fuel and purchased power	287,476	315,524	776,301	918,874
Operating and maintenance expenses	72,036	66,833	219,760	205,194
Demand side management program expenses	3,726	3,455	10,155	9,368
Depreciation and amortization	35,422	34,207	107,911	99,790
Taxes (other than income taxes)	15,016	13,991	43,472	40,144
Total operating expenses	413,676	434,010	1,157,599	1,273,370
Operating income	117,076	118,769	219,967	220,345
Other income (expense), net	103	66	203	(22)
Allowance for funds used during construction — equity	2,085	3,147	5,578	9,682
Interest charges and financing costs
Interest charges — includes other financing costs of $789, $768, $2,334 and $2,229, respectively	21,779	20,479	63,737	59,405
Public Utilities, Allowance For Funds Used During Construction, Capitalized Cost Of Debt	(1,204)	(1,846)	(3,402)	(5,694)
Total interest charges and financing costs	20,575	18,633	60,335	53,711
Income before income taxes	98,689	103,349	165,413	176,294
Income taxes	36,874	36,412	60,775	62,587
Net income	$ 61,815	$ 66,937	$ 104,638	$ 113,707

STATEMENTS OF INCOME (UNAUDITE3

STATEMENTS OF INCOME (UNAUDITED) (Parenthetical) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Interest charges and financing costs
Other financing costs	$ 789	$ 768	$ 2,334	$ 2,229

STATEMENTS OF COMPREHENSIVE INC

STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Comprehensive income:
Net income	$ 61,815	$ 66,937	$ 104,638	$ 113,707
Derivative instruments:
Reclassification of losses to net income, net of tax of $24 and $72 for each of the three and nine months ended Sept. 30, 2015 and 2014, respectively	44	44	129	129
Other comprehensive income	44	44	129	129
Comprehensive income	$ 61,859	$ 66,981	$ 104,767	$ 113,836

STATEMENTS OF COMPREHENSIVE IN5

STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED) (Parenthetical) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Derivative instruments:
Reclassification of losses to net income, tax	$ 24	$ 24	$ 72	$ 72

STATEMENTS OF CASH FLOWS (UNAUD

STATEMENTS OF CASH FLOWS (UNAUDITED) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014
Operating activities
Net income	$ 104,638	$ 113,707
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	109,629	101,514
Demand side management program amortization	1,255	1,255
Deferred income taxes	35,541	88,008
Amortization of Investment Tax Credits	(255)	(255)
Allowance for equity funds used during construction	(5,578)	(9,682)
Net derivative losses	201	201
Changes in operating assets and liabilities:
Accounts receivable	(24,416)	(10,982)
Accrued unbilled revenues	18,286	(22,164)
Inventories	3,351	(6,257)
Prepayments and other	(14,589)	(672)
Accounts payable	(6,891)	5,777
Net regulatory assets and liabilities	43,980	(11,550)
Other current liabilities	43,949	29,426
Pension and other employee benefit obligations	(9,961)	(2,535)
Change in other noncurrent assets	1,054	2,684
Change in other noncurrent liabilities	1,227	2,204
Net cash provided by operating activities	301,421	280,679
Investing activities
Utility capital/construction expenditures	(428,991)	(412,976)
Allowance for equity funds used during construction	5,578	9,682
Investments in utility money pool arrangement	(9,000)	(94,000)
Repayments from utility money pool arrangement	9,000	91,000
Net cash used in investing activities	(423,413)	(406,294)
Financing activities
Proceeds from (repayment of) short-term borrowings, net	(37,000)	(84,000)
Proceeds from Issuance of Long-term Debt	198,784	148,241
Borrowings under utility money pool arrangement	407,700	433,000
Repayments under utility money pool arrangement	(405,700)	(471,000)
Capital contributions from parent	34,535	160,000
Dividends paid to parent	(76,192)	(60,632)
Net cash provided by financing activities	122,127	125,609
Net change in cash and cash equivalents	135	(6)
Cash and cash equivalents at beginning of period	596	1,011
Cash and cash equivalents at end of period	731	1,005
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	(58,539)	(41,604)
Cash (paid) received for income taxes, net	(41,114)	26,539
Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable	$ 29,815	$ 19,538

BALANCE SHEETS (UNAUDITED)

BALANCE SHEETS (UNAUDITED) - USD ($) $ in Thousands	Sep. 30, 2015	Dec. 31, 2014
Current assets
Cash and cash equivalents	$ 731	$ 596
Accounts receivable, net	95,928	71,626
Accounts receivable from affiliates	2,097	1,983
Accrued unbilled revenues	111,001	129,287
Inventories	39,880	43,231
Regulatory assets	34,467	52,006
Derivative instruments	15,252	23,776
Deferred income taxes	79,368	51,854
Prepayments and other	46,065	31,476
Total current assets	424,789	405,835
Property, plant and equipment, net	4,061,619	3,743,141
Other assets
Regulatory assets	307,811	323,305
Derivative instruments	27,245	33,164
Other	15,977	15,859
Total other assets	351,033	372,328
Total assets	4,837,441	4,521,304
Current liabilities
Short-term debt	0	37,000
Borrowings under utility money pool arrangement	18,000	16,000
Accounts payable	153,144	160,762
Accounts payable to affiliates	17,169	19,790
Regulatory liabilities	115,925	87,723
Taxes accrued	35,772	27,208
Accrued interest	29,550	17,057
Dividends payable	24,352	27,828
Derivative instruments	3,565	3,565
Other	96,378	80,211
Total current liabilities	493,855	477,144
Deferred credits and other liabilities
Deferred income taxes	912,343	849,145
Regulatory liabilities	94,799	115,188
Asset retirement obligations	27,061	26,031
Derivative instruments	27,969	30,643
Pension and employee benefit obligations	93,640	103,670
Other	10,179	9,320
Total deferred credits and other liabilities	$ 1,165,991	$ 1,133,997
Commitments and contingencies
Capitalization
Long-term debt	$ 1,550,537	$ 1,349,691
Common stock — 200 shares authorized of $1.00 par value; 100 shares outstanding at Sept. 30, 2015 and Dec. 31, 2014, respectively	0	0
Additional paid in capital	1,199,998	1,165,463
Retained earnings	427,920	395,998
Accumulated other comprehensive loss	(860)	(989)
Total common stockholder’s equity	1,627,058	1,560,472
Total liabilities and equity	$ 4,837,441	$ 4,521,304

BALANCE SHEETS (UNAUDITED) (Par

BALANCE SHEETS (UNAUDITED) (Parenthetical) - $ / shares	Sep. 30, 2015	Dec. 31, 2014
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

Management's Opinion

Management's Opinion	9 Months Ended
	Sep. 30, 2015
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Management's Opinion	In the opinion of management, the accompanying unaudited financial statements contain all adjustments necessary to present fairly, in accordance with accounting principles generally accepted in the United States of America (GAAP), the financial position of SPS as of Sept. 30, 2015 , and Dec. 31, 2014 ; the results of its operations, including the components of net income and comprehensive income, for the three and nine months ended Sept. 30, 2015 and 2014 ; and its cash flows for the nine months ended Sept. 30, 2015 and 2014 . All adjustments are of a normal, recurring nature, except as otherwise disclosed. Management has also evaluated the impact of events occurring after Sept. 30, 2015 up to the date of issuance of these financial statements. These statements contain all necessary adjustments and disclosures resulting from that evaluation. The Dec. 31, 2014 balance sheet information has been derived from the audited 2014 financial statements included in the SPS Annual Report on Form 10-K for the year ended Dec. 31, 2014 . These notes to the financial statements have been prepared pursuant to the rules and regulations of the SEC for Quarterly Reports on Form 10-Q. Certain information and note disclosures normally included in financial statements prepared in accordance with GAAP on an annual basis have been condensed or omitted pursuant to such rules and regulations. For further information, refer to the financial statements and notes thereto included in the SPS Annual Report on Form 10-K for the year ended Dec. 31, 2014 , filed with the SEC on Feb. 23, 2015. Due to the seasonality of SPS’ electric sales, interim results are not necessarily an appropriate base from which to project annual results.

Summary of Significant Accounti

Summary of Significant Accounting Policies	9 Months Ended
	Sep. 30, 2015
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	Summary of Significant Accounting Policies The significant accounting policies set forth in Note 1 to the financial statements in the SPS Annual Report on Form 10-K for the year ended Dec. 31, 2014 , appropriately represent, in all material respects, the current status of accounting policies and are incorporated herein by reference.

Accounting Pronouncements

Accounting Pronouncements	9 Months Ended
	Sep. 30, 2015
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]
Accounting Pronouncements	Accounting Pronouncements Recently Issued Revenue Recognition — In May 2014, the Financial Accounting Standards Board (FASB) issued Revenue from Contracts with Customers, Topic 606 (Accounting Standards Update (ASU) No. 2014-09) , which provides a framework for the recognition of revenue, with the objective that recognized revenues properly reflect amounts an entity is entitled to receive in exchange for goods and services. The new guidance also includes additional disclosure requirements regarding revenue, cash flows and obligations related to contracts with customers. As a result of the FASB’s deferral of the standard’s required implementation date in July 2015, the guidance is effective for interim and annual reporting periods beginning after Dec. 15, 2017. SPS is currently evaluating the impact of adopting ASU 2014-09 on its financial statements. 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. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15. 2015, and early adoption is permitted. SPS does not expect the implementation of ASU 2015-02 to have a material 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 amends existing guidance to require the presentation of debt issuance costs on the balance sheet as a deduction from the carrying amount of the related debt, instead of an asset. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, 2015, and early adoption is permitted. Other than the prescribed reclassification of assets to an offset of debt on the balance sheets, SPS does not expect the implementation of ASU 2015-03 to have a material impact on its financial statements. 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 removes the requirement to categorize within the fair value hierarchy the fair values for investments measured using a net asset value methodology. This guidance will be effective on a retrospective basis for interim and annual reporting periods beginning after Dec. 15, 2015, and early adoption is permitted. Other than the reduced disclosure requirements, SPS does not expect the implementation of ASU 2015-07 to have a material impact on its financial statements.

Selected Balance Sheet Data

Selected Balance Sheet Data	9 Months Ended
	Sep. 30, 2015
Balance Sheet Related Disclosures [Abstract]
Selected Balance Sheet Data	Selected Balance Sheet Data (Thousands of Dollars) Sept. 30, 2015 Dec. 31, 2014 Accounts receivable, net Accounts receivable $ 102,408 $ 77,465 Less allowance for bad debts (6,480 ) (5,839 ) $ 95,928 $ 71,626 (Thousands of Dollars) Sept. 30, 2015 Dec. 31, 2014 Inventories Materials and supplies $ 25,595 $ 24,738 Fuel 14,285 18,493 $ 39,880 $ 43,231 (Thousands of Dollars) Sept. 30, 2015 Dec. 31, 2014 Property, plant and equipment, net Electric plant $ 5,673,759 $ 5,376,606 Construction work in progress 338,889 238,519 Total property, plant and equipment 6,012,648 5,615,125 Less accumulated depreciation (1,951,029 ) (1,871,984 ) $ 4,061,619 $ 3,743,141

Income Taxes

Income Taxes	9 Months Ended
	Sep. 30, 2015
Income Tax Disclosure [Abstract]
Income Taxes	Income Taxes Except to the extent noted below, Note 6 to the financial statements included in SPS’ Annual Report on Form 10-K for the year ended Dec. 31, 2014 appropriately represents, in all material respects, the current status of other income tax matters, and are incorporated herein by reference. Federal Audit — SPS is a member of the Xcel Energy affiliated group that files a consolidated federal income tax return. In the third quarter of 2012, the Internal Revenue Service (IRS) commenced an examination of tax years 2010 and 2011 , including the 2009 carryback claim. As of Sept. 30, 2015, the IRS had proposed an adjustment to the federal tax loss carryback claims that would result in $13 million of income tax expense for the 2009 through 2011 claims, the recently filed 2013 claim, and the anticipated claim for 2014. SPS is not expected to accrue any income tax expense related to this adjustment. As of Sept. 30, 2015, the IRS had begun the appeals process; however, the outcome and timing of a resolution are uncertain. The statute of limitations applicable to Xcel Energy’s 2009-2011 federal income tax returns expires in December 2016 following an extension to allow additional time for the appeals process. In the third quarter of 2015, the IRS commenced an examination of tax years 2012 and 2013 . As of Sept. 30, 2015, the IRS had not proposed any material adjustments to tax years 2012 and 2013. State Audits — SPS is a member of the Xcel Energy affiliated group that files consolidated state income tax returns. As of Sept. 30, 2015, SPS’ earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations is 2009 . There are currently no state income tax audits in progress. Unrecognized Tax Benefits — The unrecognized tax benefit balance includes permanent tax positions, which if recognized would affect the annual effective tax rate (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) Sept. 30, 2015 Dec. 31, 2014 Unrecognized tax benefit — Permanent tax positions $ 1.6 $ 1.5 Unrecognized tax benefit — Temporary tax positions 12.7 11.7 Total unrecognized tax benefit $ 14.3 $ 13.2 The unrecognized tax benefit amounts were reduced by the tax benefits associated with net operating loss (NOL) and tax credit carryforwards. The amounts of tax benefits associated with NOL and tax credit carryforwards are as follows: (Millions of Dollars) Sept. 30, 2015 Dec. 31, 2014 NOL and tax credit carryforwards $ (6.3 ) $ (4.8 ) It is reasonably possible that SPS’ amount of unrecognized tax benefits could significantly change in the next 12 months as the IRS appeals process and audit progress and state audits resume. As the IRS examination moves closer to completion, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $2 million . The payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryforwards. The payables for interest related to unrecognized tax benefits at Sept. 30, 2015 and Dec. 31, 2014 were not material. No amounts were accrued for penalties related to unrecognized tax benefits as of Sept. 30, 2015 or Dec. 31, 2014.

Rate Matters

Rate Matters	9 Months Ended
	Sep. 30, 2015
Public Utilities, General Disclosures [Abstract]
Rate Matters	Rate Matters Except to the extent noted below, the circumstances set forth in Note 10 to the financial statements included in SPS’ Annual Report on Form 10-K for the year ended Dec. 31, 2014 and in Note 5 to the financial statements included in SPS’ Quarterly Reports on Form 10-Q for the quarterly periods ended March 31, 2015 and June 30, 2015, appropriately represent, in all material respects, the current status of other rate matters, and are incorporated herein by reference. Pending Regulatory Proceedings — Public Utility Commission of Texas (PUCT) Texas 2015 Electric Rate Case — In December 2014, SPS filed a retail electric rate case in Texas seeking an overall increase in annual revenue of approximately $64.8 million , or 6.7 percent . The filing was based on a historic test year (HTY) ending June 2014, adjusted for known and measurable changes, a return on equity (ROE) of 10.25 percent , an electric rate base of approximately $1.6 billion and an equity ratio of 53.97 percent . In March 2015, SPS revised its requested increase to $58.9 million based on updated information. SPS is seeking a waiver of the PUCT post-test year adjustment rule which would allow for inclusion of $392 million (SPS total company) additional capital investment for the period July 1, 2014 through Dec. 31, 2014. In June 2015, SPS filed rebuttal testimony supporting a revised rate increase of approximately $42.1 million , or 4.4 percent . On Oct. 12, 2015, the administrative law judges (ALJs) issued their Proposal for Decision (PFD) and recommended a rate increase of approximately $1.2 million , based on a ROE of 9.70 percent and an equity ratio of 53.97 percent . The following table reflects the positions of Alliance of Xcel Municipalities (AXM), the Office of Public Utility Counsel (OPUC), the PUCT Staff (Staff), SPS as well as the estimated recommendation of the ALJs: SPS Rebuttal Testimony ALJs’ PFD (a) (Millions of Dollars) AXM OPUC Staff SPS’ revised rate request $ 58.9 $ 58.9 $ 58.9 $ 58.9 $ 42.1 Investment for capital expenditures — post-test year adjustments (11.3 ) (23.8 ) (23.8 ) — (16.7 ) Lower ROE (10.9 ) (13.5 ) (12.1 ) — (6.3 ) Rate base adjustments (largely the removal of the prepaid pension asset) (6.2 ) (6.8 ) — — — O&M expense adjustments (13.7 ) (11.0 ) (7.9 ) (1.6 ) (5.3 ) Depreciation expense (13.3 ) — — — (3.9 ) Property taxes — (1.2 ) (4.4 ) (1.8 ) (3.7 ) Revenue adjustments (2.2 ) (0.2 ) — — — Wholesale load reductions (13.2 ) — (11.1 ) — — Southwest Power Pool (SPP) transmission expansion plan — — — (7.3 ) (4.2 ) Other, net (1.7 ) (0.6 ) (2.2 ) (1.8 ) (0.6 ) Total recommendation $ (13.6 ) $ 1.8 $ (2.6 ) $ 46.4 $ 1.4 Adjustment to move rate case expenses to a separate docket — — — (4.3 ) (0.2 ) Recommendation, excluding rate case expenses $ (13.6 ) $ 1.8 $ (2.6 ) $ 42.1 $ 1.2 (a) The ALJs’ recommendation reflects proposed adjustments to SPS’ rebuttal testimony, as of Oct. 12, 2015, which supports a $42.1 million rate increase. SPS subsequently filed a letter notifying the PUCT it had concerns regarding the calculation. On Oct. 28, 2015, the Staff issued a revised calculation reflecting corrections to the PFD. The ALJs’ revised recommended rate increase is $14.4 million . New rates will be made effective retroactive to June 11, 2015 as established by the PUCT. A PUCT decision is expected in December 2015. Pending Regulatory Proceedings — New Mexico Public Regulation Commission (NMPRC) New Mexico 2015 Electric Rate Case — In October 2015, SPS filed an electric rate case with the NMPRC for a net increase in base rates of approximately $24.3 million for the New Mexico retail jurisdiction. The proposed net amount reflects an increase in non-fuel base rates of $45.4 million and a decrease in base fuel revenue of approximately $21.1 million . The decrease in base fuel revenue will be reflected in adjustments collected through the fuel and purchased power adjustment clause. The rate filing is based on a June 30, 2015 HTY adjusted for known and measurable changes, a requested ROE of 10.25 percent , an electric jurisdictional rate base of approximately $734 million and an equity ratio of 53.97 percent . The major components of the requested rate increase are summarized below: (Millions of Dollars) Request 2015 base period deficiency $ 19.7 Capital expenditures — post-test year adjustments 12.3 Depreciation, higher rates reflecting changes in depreciable lives, interim retirements and net salvage 3.7 Transmission revenue and expense, including charges paid to SPP for construction of regionally shared transmission projects 2.0 ROE, reflecting an increase from 9.96 percent to 10.25 percent 1.6 Rider revenue adjustments - gross receipts tax 1.3 Other, net 4.8 Requested rate increase $ 45.4 A NMPRC decision and implementation of final rates is anticipated in the second half of 2016. In June 2015, the NMPRC dismissed a rate case filing using a future test year based on new precedent. SPS has appealed that decision to the New Mexico Supreme Court. Recently Concluded Regulatory Proceedings — Federal Energy Regulatory Commission (FERC) SPS – Global Settlement Agreement — In August 2015, SPS, Golden Spread Electric Cooperative, Inc. (Golden Spread), four New Mexico Cooperatives, West Texas Municipal Power Agency (WTMPA), Public Service Company of New Mexico (PNM) and Tri-County Electric Cooperative, Inc. (Tri-County) filed a settlement agreement with the FERC that would provide a comprehensive resolution of nine pending matters in dispute between SPS and these wholesale production and transmission customers, including the 2004 FERC Complaint Case , the Wholesale Rate Complaints , the 2015 Formula Rate Change Filing and the Sale of Texas Transmission Assets as discussed below. Key terms of the settlement agreement include: • A settlement payment to Golden Spread for $44.9 million and withdrawal of the SPS and the New Mexico Cooperatives’ requests for rehearing of the August 2013 FERC order ruling that SPS is a 3 coincident peak (CP) system; • A settlement payment to PNM of $4.2 million and the withdrawal of the PNM request for rehearing of the August 2013 FERC order denying PNM’s challenge to the 2008 FERC ruling regarding SPS’ fuel cost adjustment practices; • Withdrawal of the Golden Spread Wholesale Rate Complaints, resulting in no change to the then-effective production and transmission ROEs for the period April 20, 2012 through Oct. 19, 2014, and withdrawal of the SPS appeal of the FERC orders in those proceedings to the United States District Court of Appeals for the District of Columbia Circuit (D.C. Circuit); • A reduction in the SPS transmission ROE to 10.5 percent (including the 50 basis point SPP regional transmission organization membership adder) and the production ROE in the Golden Spread and New Mexico Cooperatives production formula rates to 10.0 percent effective Oct. 20, 2014, and establishment of a limited moratorium that precludes any increase or decrease in these effective ROEs through 2019; • Utilization of the 12 CP production cost allocation methodology in the Golden Spread, New Mexico Cooperatives and WTMPA production formula rates and a moratorium precluding all settlement parties from seeking to change from the 12 CP methodology during the remaining term of the Golden Spread production contract (currently scheduled to expire in May 2019); • SPS agrees to reduce its production formula rates retroactive to Jan. 1, 2015 to reflect full year implementation of reduced depreciation and certain other costs; the FERC had allowed these reductions to be effective July 1, 2015; • SPS agrees to make certain revisions to its transmission formula rate, effective Jan. 1, 2016, to provide for a sharing of the wholesale portion of any gain on a future sale of transmission assets; other parties agree not to challenge the non-sharing of the gain SPS recorded on prior and current transmission asset transactions with Sharyland Distribution and Transmission Services, LLC (Sharyland) and Oncor Electric Delivery Company LLC; • SPS agrees not to file with FERC to increase transmission depreciation rate rates effective prior to Jan. 1, 2017; and • SPS agrees not to transfer Tri-County from its current stated rate production service agreement to a production formula rate effective prior to Jan. 1, 2017. Tri-County agrees that it will not contest implementation of the formula rate as of that date. On Oct. 29, 2015, the FERC issued an order approving the settlement agreement. The terms are effective 30 days after issuance. As a result of the settlement, SPS expects to recognize a net gain of approximately $7.9 million in the fourth quarter of 2015. The settlement also resolves the following: 2004 FERC Complaint Case Orders — In August 2013, the FERC issued an order related to a 2004 complaint case brought by Golden Spread, a wholesale cooperative customer, and PNM, a former wholesale customer, and also issued an Order on Initial Decision in a subsequent 2006 production rate case filed by SPS. The original complaints included two key components: 1) a base rate complaint, including the appropriate demand-related CP cost allocator; and 2) a claim regarding alleged inappropriate fuel cost adjustment practices. The FERC had determined in April 2008 that the demand-related cost allocator and fuel cost adjustment practices utilized by SPS were appropriate. In the August 2013 Orders, the FERC reversed its prior demand-related cost allocator decision. The FERC stated that it had erred in its initial analysis and concluded that the SPS system was a 3 CP rather than a 12 CP system. The FERC also clarified its previous ruling on fuel cost adjustment practices and reaffirmed that the refunds in question should only apply to firm requirements customers. In September 2013, SPS, the New Mexico Cooperatives and PNM each filed requests for rehearing of the FERC ruling on the CP allocation and/or refund decision. As of Dec. 31, 2014, SPS had accrued $50.4 million related to the August 2013 Orders and an additional $1.9 million of principal and interest has been accrued during 2015. Wholesale Rate Complaints — In April 2012, Golden Spread filed a rate complaint alleging that the base ROE included in the SPS production formula rate for Golden Spread of 10.25 percent , and the SPS transmission formula rate ROE of 11.27 percent are unjust and unreasonable, and requested that the base ROEs be reduced to 9.15 percent and 9.65 percent , respectively, effective April 20, 2012. In July 2013, Golden Spread filed a second complaint, again asking that the base ROE in the SPS production formula rate for Golden Spread and transmission formula rates be reduced to 9.15 percent and 9.65 percent , respectively, effective July 19, 2013. In June 2014, the FERC issued orders consolidating these ROE complaints, setting the complaints for hearing procedures and granting the complainant’s requested refund effective dates. SPS subsequently sought rehearing. In May 2015, FERC denied rehearing. In July 2015, SPS appealed the FERC orders to the D.C. Circuit. A third ROE rate complaint was filed in October 2014 by Golden Spread, along with the New Mexico Cooperatives and WTMPA, requesting that the ROE in the SPS production formula rates for Golden Spread and the New Mexico Cooperatives and SPS transmission formula rate, be reduced to 8.61 percent and 9.11 percent , respectively, effective Oct. 20, 2014. In January 2015, the FERC issued an order setting the third complaint for hearing procedures and granting the complainants’ requested refund effective date. SPS subsequently sought rehearing. FERC has not acted on the SPS rehearing request. 2015 Formula Rate Change Filing — In January 2015, SPS filed to revise the production formula rates for Golden Spread, the four New Mexico Cooperatives and WTMPA, effective Feb. 1, 2015. The filing proposed several modifications, including a reduction in wholesale depreciation rates and the use of a 12 CP demand-related cost allocator for all wholesale customers. On March 31, 2015, the FERC accepted this filing, effective July 1, 2015, subject to refund and settlement judge or hearing procedures. Sale of Texas Transmission Assets — In March 2013, SPS reached an agreement to sell certain segments of SPS’ transmission lines and two related substations to Sharyland. In 2013, SPS received all necessary regulatory approvals for the transaction. In December 2013, SPS received $37.1 million and recognized a pre-tax gain of $13.6 million and regulatory liabilities for retail jurisdictional gain sharing of $7.2 million . The gain is reflected in the consolidated statement of income as a reduction to operating and maintenance (O&M) expenses. In December 2014, Golden Spread submitted a preliminary challenge under the SPS transmission formula rate procedures asserting the gain should be shared with wholesale transmission customers. SPS disputed this claim. In October 2015, the FERC denied rehearing on the matter.

Commitments and Contingencies

Commitments and Contingencies	9 Months Ended
	Sep. 30, 2015
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Commitments and Contingencies Except to the extent noted below and in Note 5 above, the circumstances set forth in Note 5, Notes 10 and 11 to the financial statements included in SPS’ Annual Report on Form 10-K for the year ended Dec. 31, 2014 and in Notes 5 and 6 to the financial statements included in SPS’ Quarterly Reports on Form 10-Q for the quarterly periods ended March 31, 2015 and June 30, 2015, appropriately represent, in all material respects, the current status of commitments and contingent liabilities, and are incorporated herein by reference. The following include commitments, contingencies and unresolved contingencies that are material to SPS’ financial position. Purchased Power Agreements (PPAs) Under certain PPAs, SPS purchases power from independent power producing entities that own natural gas fueled power plants for which SPS is required to reimburse natural gas fuel costs, or to participate in tolling arrangements under which SPS procures the natural gas required to produce the energy that it purchases. These specific PPAs create a variable interest in the associated independent power producing entity. SPS had approximately 827 megawatts (MW) of capacity under long-term PPAs as of Sept. 30, 2015 and Dec. 31, 2014 , with entities that have been determined to be variable interest entities. 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. These agreements have expiration dates through 2033 . Environmental Contingencies Environmental Requirements Water Federal Clean Water Act (CWA) Effluent Limitations Guidelines (ELG) — In September 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 is currently reviewing the final rule and cannot predict, at this time, whether the costs of compliance with the final rule will have a material impact on the results of operations, financial position or cash flows. SPS believes that compliance costs would be recoverable through regulatory mechanisms. 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. The rule went into effect in August 2015. On Oct. 9, 2015, the U.S. Court of Appeals for the Sixth Circuit issued a nationwide stay of the final rule, pending further legal proceedings. Air Green House Gas (GHG) Emission Standard for Existing Sources — In June 2014, the EPA published its proposed rule on GHG emission standards for existing power plants. A final rule was published in October 2015. States must develop implementation plans by September 2016, with the possibility of an extension to September 2018. If a state decides not to submit a plan, the EPA will prepare a federal plan for the state. In addition, the EPA published a proposed model federal plan and will provide a 90 -day public comment period on the federal plan once it has been published in the Federal Register. Among other things, the rule requires that state plans include enforceable measures to ensure emissions from existing power plants in the state achieve the EPA’s state-specific interim (2022-2029) and final (2030 and thereafter) emission performance targets. The plan will likely require additional emission reductions in states in which SPS operates. Until SPS has reviewed the final rule and has more information about state implementation plans, SPS cannot predict whether the costs of compliance with the final rule will have a material impact on the results of operations, financial position or cash flows. SPS believes that compliance costs will be recoverable through regulatory mechanisms. GHG New Source Performance Standard (NSPS) Proposal — In January 2014, the EPA re-proposed a GHG NSPS for newly constructed power plants which would set performance standards (maximum carbon dioxide emission rates) for coal- and natural gas-fired power plants. For coal power plants, the NSPS requires an emissions level equivalent to partial carbon capture and storage (CCS) technology; for natural gas-fired power plants, the NSPS reflects emissions levels from combined cycle technology with no CCS. The NSPS does not apply to modified or reconstructed existing power plants. In addition, installation of control equipment on existing plants would not constitute a “modification” to those plants under the NSPS program. The final rule was published in October 2015. SPS does not anticipate the costs of compliance with the final rule will have a material impact on the results of operations, financial position or cash flows. GHG NSPS for Modified and Reconstructed Power Plants — In June 2014, the EPA published a proposed NSPS that would apply to GHG emissions from power plants that are modified or reconstructed. A final rule was published in October 2015. A modification is a change to an existing source that increases the maximum achievable hourly rate of emissions. A reconstruction involves the replacement of components at a unit to the extent that the capital cost of the new components exceeds 50 percent of the capital cost of an entirely new comparable unit. The standards do not require installation of CCS technology. Instead, the standard for coal-fired power plants requires a combination of best operating practices and equipment upgrades. The standards for natural gas-fired power plants require emissions standards based on efficient combined cycle technology. These requirements would only apply if SPS were to modify or reconstruct an existing power plant in the future in a way that triggers applicability of this rule. Cross-State Air Pollution Rule (CSAPR) — CSAPR addresses long range transport of particulate matter (PM) and ozone by requiring reductions in sulfur dioxide (SO 2 ) and nitrous oxide (NOx) from utilities in the eastern half of the United States, including Texas, using an emissions trading program. In August 2012, the D.C. Circuit vacated the CSAPR and remanded it back to the EPA. The D.C. Circuit stated the EPA must continue administering the Clean Air Interstate Rule (CAIR) pending adoption of a valid replacement. In April 2014, the U.S. Supreme Court reversed and remanded the case to the D.C. Circuit. The Supreme Court held that the EPA’s rule design did not violate the Clean Air Act (CAA) and that states had received adequate opportunity to develop their own plans. Because the D.C. Circuit overturned the CSAPR on two over-arching issues, there are many other issues the D.C. Circuit did not rule on that were considered on remand. In July 2015, the D.C. Circuit issued an opinion which found the reduction budgets exceed what is necessary for Texas to reduce its impact on downwind states that do not meet ambient air quality standards. The D.C. Circuit remanded the matter to the EPA to reconsider the emission budgets. While the EPA reconsiders emission budgets, the D.C. Circuit left CSAPR in effect. In October 2014, the D.C. Circuit granted the EPA’s request to begin to implement CSAPR by imposing its 2012 compliance obligations starting in January 2015. While the litigation continues, the EPA is administering the CSAPR in 2015. Multiple changes to the SPS system since 2011 will substantially reduce estimated costs of complying with the CSAPR. These include the addition of 700 MW of wind power, the construction of Jones Units 3 and 4, reduced wholesale load, new PPAs, installation of NOx combustion controls on Tolk Units 1 and 2 and completion of certain transmission projects. As a result, SPS estimates compliance with the CSAPR in 2015 will not have a material impact on the results of operations, financial position or cash flows. Electric Generating Unit (EGU) Mercury and Air Toxics Standards (MATS) Rule — The final EGU MATS rule became effective in April 2012. The EGU MATS rule sets emission limits for acid gases, mercury and other hazardous air pollutants and requires coal-fired utility facilities greater than 25 MW to demonstrate compliance within three to four years of the effective date. In 2014, the U.S. Supreme Court decided to review the D.C. Circuit’s decision that upheld the MATS standard. By April 2015, the MATS compliance deadline, SPS had met the EGU MATS rule through a combination of emission control projects and existing controls. Mercury controls were installed in SPS’ Tolk and Harrington plants for a capital cost of $8 million . In June 2015, the U.S. Supreme Court found that the EPA acted unreasonably by not considering the cost to regulate mercury and other hazardous air pollutants. The D.C. Circuit, on remand, will decide whether to leave MATS in effect while the EPA considers such costs in making a new determination. SPS believes EGU MATS costs will be recoverable through regulatory mechanisms and does not anticipate 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. In 2005, the EPA amended the best available retrofit technology (BART) requirements of its regional haze rules, which require the installation and operation of emission controls for industrial facilities emitting air pollutants that reduce visibility in certain national parks and wilderness areas. In its first regional haze state implementation plan (SIP), Texas identified the SPS facilities that will have to reduce SO 2 , NOx and PM emissions under BART and set emissions limits for those facilities. Harrington Units 1 and 2 are potentially subject to BART. 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 May 2012, the EPA deferred its review of the SIP in its final rule allowing states to find that CSAPR compliance meets BART requirements for EGUs. In December 2014, the EPA proposed to approve the BART portion of the SIP, with the exception that the EPA would substitute CSAPR compliance for Texas’ reliance on CAIR. The EPA has indicated that it expects to issue its final rule in December 2015. In May 2014, the EPA issued a request for information under the CAA related to SO 2 control equipment at Tolk Units 1 and 2. In December 2014, the EPA proposed to disapprove the reasonable progress portions of the SIP and instead adopt a Federal Implementation Plan. The EPA proposed to require dry scrubbers on both Tolk units to reduce SO 2 emissions to help achieve reasonable progress goals for Texas and Oklahoma national parks and wilderness areas. As proposed, the dry scrubbers would need to be installed and operating within five years of the EPA’s final action, currently expected in December 2015. Whether dry scrubbers are required is dependent on the EPA’s final decision. If required, they would cost approximately $600 million , with an annual operating cost of approximately $10.4 million . SPS believes these costs would be recoverable through regulatory mechanisms and therefore does not expect a material impact on results of operations, financial position or cash flows. Implementation of the National Ambient Air Quality Standard (NAAQS) for SO 2 — The EPA adopted a more stringent NAAQS for SO 2 in 2010. In 2013, the EPA designated areas as not attaining the revised NAAQS, which did not include any areas where Xcel Energy operates power plants. However, many other areas of the country were unable to be classified by the EPA due to a lack of air monitors. Following a lawsuit alleging that the EPA had not completed its area designations in the time required by the CAA and under a consent decree 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. The Texas Commission on Environmental Quality (TCEQ) made recommendations for unclassified and nonattainment areas to the EPA in September 2015. The EPA’s final decision is expected by summer 2016. If an area is designated nonattainment, the respective states will need to evaluate all SO 2 sources in the area. The state would then submit an implementation plan for the respective areas which would be due in 18 months, designed to achieve the NAAQS within five years. The TCEQ could require additional SO 2 controls on one or more of the units at Tolk and Harrington. SPS cannot evaluate the impacts of this ruling 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 for a plant, compliance costs 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 October 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. 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.

Borrowings and Other Financing

Borrowings and Other Financing Instruments	9 Months Ended
	Sep. 30, 2015
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 Sept. 30, 2015 Twelve Months Ended Dec. 31, 2014 Borrowing limit $ 100 $ 100 Amount outstanding at period end 18 16 Average amount outstanding 47 9 Maximum amount outstanding 100 100 Weighted average interest rate, computed on a daily basis 0.41 % 0.22 % Weighted average interest rate at period end 0.38 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 Sept. 30, 2015 Twelve Months Ended Dec. 31, 2014 Borrowing limit $ 400 $ 400 Amount outstanding at period end — 37 Average amount outstanding 135 83 Maximum amount outstanding 246 241 Weighted average interest rate, computed on a daily basis 0.45 % 0.26 % Weighted average interest rate at period end N/A 0.47 Letters of Credit — SPS uses letters of credit, generally with terms of one year , to provide financial guarantees for certain operating obligations. At Sept. 30, 2015 and Dec. 31, 2014 , there were $10 million and $30 million , respectively, of letters of credit outstanding under the credit facility. The contract amounts of these letters of credit approximate their fair value and are subject to fees. Credit Facility — In order to use its commercial paper program to fulfill short-term funding needs, SPS must have a revolving credit facility in place at least equal to the amount of its commercial paper borrowing limit and cannot issue commercial paper in an aggregate amount exceeding available capacity under this credit facility. The line of credit provides short-term financing in the form of notes payable to banks, letters of credit and back-up support for commercial paper borrowings. At Sept. 30, 2015 , SPS had the following committed credit facility available (in millions of dollars): Credit Facility (a) Drawn (b) Available $ 400 $ 10 $ 390 (a) This credit facility expires in October 2019. (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 Sept. 30, 2015 and Dec. 31, 2014 . Long-Term Borrowings In September 2015, SPS issued $200 million of 3.3 percent first mortgage bonds due June 15, 2024.

Fair Value of Financial Assets

Fair Value of Financial Assets and Liabilities	9 Months Ended
	Sep. 30, 2015
Fair Value Disclosures [Abstract]
Fair Value of Financial Assets and Liabilities	Fair Value of Financial Assets and Liabilities Fair Value Measurements The accounting guidance for fair value measurements and disclosures provides a single definition of fair value and requires certain disclosures about assets and liabilities measured at fair value. A hierarchical framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value is established by this guidance. The three levels in the hierarchy are as follows: Level 1 — Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. The types of assets and liabilities included in Level 1 are highly liquid and actively traded instruments with quoted prices. Level 2 — Pricing inputs are other than quoted prices in active markets, but are either directly or indirectly observable as of the reporting date. The types of assets and liabilities included in Level 2 are typically either comparable to actively traded securities or contracts, or priced with models using highly observable inputs. Level 3 — Significant inputs to pricing have little or no observability as of the reporting date. The types of assets and liabilities included in Level 3 are those valued with models requiring significant management judgment or estimation. Specific valuation methods include the following: Cash equivalents — The fair values of cash equivalents are generally based on cost plus accrued interest; money market funds are measured using quoted net asset values. Interest rate derivatives — The fair values of interest rate derivatives are based on broker quotes that utilize current market interest rate forecasts. Commodity derivatives — The methods used to measure the fair value of commodity derivative forwards and options utilize forward prices and volatilities, as well as pricing adjustments for specific delivery locations, and are generally assigned a Level 2. When contractual settlements extend to periods beyond those readily observable on active exchanges or quoted by brokers, the significance of the use of less observable forecasts of long-term forward prices and volatilities on a valuation is evaluated, and may result in Level 3 classification. Electric commodity derivatives held by SPS include transmission congestion instruments purchased from the SPP, generally referred to as financial transmission rights (FTRs). FTRs purchased from a regional transmission organization (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 Sept. 30, 2015, accumulated other comprehensive losses related to interest rate derivatives included $0.2 million of net losses expected to be reclassified into earnings during the next 12 months as the related hedged interest rate transactions impact earnings, including forecasted amounts for unsettled hedges, as applicable. Wholesale and Commodity Trading Risk — SPS conducts various wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy and energy-related instruments. SPS’ risk management policy allows management to conduct these activities within guidelines and limitations as approved by its risk management committee, which is made up of management personnel not directly involved in the activities governed by this policy. Commodity Derivatives — SPS enters into derivative instruments to manage variability of future cash flows from changes in commodity prices in its electric utility operations, as well as for trading purposes. This could include the purchase or sale of energy or energy-related products and FTRs. The following table details the gross notional amounts of commodity FTRs at Sept. 30, 2015 and Dec. 31, 2014: (Amounts in Thousands) (a) Sept. 30, 2015 Dec. 31, 2014 Megawatt hours of electricity 9,412 6,930 (a) Amounts are not reflective of net positions in the underlying commodities. Impact of Derivative Activities on Income and Accumulated Other Comprehensive Loss — Pre-tax losses related to interest rate derivatives reclassified from accumulated other comprehensive loss into earnings were $0.1 million for the three months ended Sept. 30, 2015 and 2014, and $0.2 million for the nine months ended Sept. 30, 2015 and 2014. During the three and nine months ended Sept. 30, 2015, changes in the fair value of FTRs resulted in pre-tax net losses of $0.7 million and $2.7 million , respectively, recognized as regulatory assets and liabilities. For the three and nine months ended Sept. 30, 2014, changes in the fair value of FTRs resulted in pre-tax net losses of $1.2 million and $3.6 million , respectively, recognized 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 losses of $0.7 million and $2.3 million , respectively, were recognized for the three and nine months ended Sept. 30, 2015, respectively, recorded to electric fuel and purchased power. For the three and nine months ended Sept. 30, 2014, FTR settlement losses of $1.2 million and $0.3 million , respectively, were recognized and 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 three and nine months ended Sept. 30, 2015 and 2014. Therefore, no gains or losses from fair value hedges or related hedged transactions were recognized for these periods. 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 and transmission activities. At Sept. 30, 2015, one of SPS’ nine most significant counterparties for these activities, comprising $2.7 million or 3 percent of this credit exposure, had investment grade credit ratings from Standard & Poor’s Ratings Services, Moody’s Investor Services or Fitch Ratings. Seven of the nine most significant counterparties, comprising $54.8 million or 53 percent of this credit exposure, were not rated by these agencies, but based on SPS’ internal analysis, had credit quality consistent with investment grade. Another of these significant counterparties, comprising $0.1 million or less than 1 percent of this credit exposure, had credit quality less than investment grade, based on SPS’ internal analysis. All nine of these significant counterparties are RTOs, municipal or cooperative electric entities or other utilities. 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 Sept. 30, 2015: Sept. 30, 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 $ — $ — $ 13,594 $ 13,594 $ (6,234 ) $ 7,360 Total current derivative assets $ — $ — $ 13,594 $ 13,594 $ (6,234 ) 7,360 PPAs (a) 7,892 Current derivative instruments $ 15,252 Noncurrent derivative assets PPAs (a) $ 27,245 Noncurrent derivative instruments $ 27,245 Current derivative liabilities Other derivative instruments: Electric commodity $ — $ — $ 6,234 $ 6,234 $ (6,234 ) $ — Total current derivative liabilities $ — $ — $ 6,234 $ 6,234 $ (6,234 ) — PPAs (a) 3,565 Current derivative instruments $ 3,565 Noncurrent derivative liabilities PPAs (a) $ 27,969 Noncurrent derivative instruments $ 27,969 (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 Sept. 30, 2015. At Sept. 30, 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 for each of the fair value hierarchy levels, SPS’ derivative assets and liabilities measured at fair value on a recurring basis at Dec. 31, 2014: Dec. 31, 2014 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 $ — $ — $ 25,774 $ 25,774 $ (9,890 ) $ 15,884 Total current derivative assets $ — $ — $ 25,774 $ 25,774 $ (9,890 ) 15,884 PPAs (a) 7,892 Current derivative instruments $ 23,776 Noncurrent derivative assets PPAs (a) $ 33,164 Noncurrent derivative instruments $ 33,164 Current derivative liabilities Other derivative instruments: Electric commodity $ — $ — $ 9,890 $ 9,890 $ (9,890 ) $ — Total current derivative liabilities $ — $ — $ 9,890 $ 9,890 $ (9,890 ) — PPAs (a) 3,565 Current derivative instruments $ 3,565 Noncurrent derivative liabilities PPAs (a) $ 30,643 Noncurrent derivative instruments $ 30,643 (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, 2014. At Dec. 31, 2014, 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 three and nine months ended Sept. 30, 2015 and 2014: Three Months Ended Sept. 30 (Thousands of Dollars) 2015 2014 Balance at July 1 $ 11,463 $ 33,942 Purchases 408 4,429 Settlements (7,409 ) (8,346 ) Net transactions recorded during the period: Gains (losses) recognized as regulatory assets and liabilities 2,898 (7,785 ) Balance at Sept. 30 $ 7,360 $ 22,240 Nine Months Ended Sept. 30 (Thousands of Dollars) 2015 2014 Balance at Jan. 1 $ 15,884 $ 9,933 Purchases 22,621 43,904 Settlements (25,810 ) (23,001 ) Net transactions recorded during the period: Losses recognized as regulatory assets and liabilities (5,335 ) (8,596 ) Balance at Sept. 30 $ 7,360 $ 22,240 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 three and nine months ended Sept. 30, 2015 and 2014. Fair Value of Long-Term Debt As of Sept. 30, 2015 and Dec. 31, 2014 , other financial instruments for which the carrying amount did not equal fair value were as follows: Sept. 30, 2015 Dec. 31, 2014 (Thousands of Dollars) Carrying Amount Fair Value Carrying Amount Fair Value Long-term debt, including current portion $ 1,550,537 $ 1,713,069 $ 1,349,691 $ 1,572,414 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 Sept. 30, 2015 and Dec. 31, 2014 , and given the observability of the inputs to these estimates, the fair values presented for long-term debt have been assigned a Level 2.

Other Income (Expense), Net

Other Income (Expense), Net	9 Months Ended
	Sep. 30, 2015
Other Income and Expenses [Abstract]
Other Income (Expense), Net	Other Income (Expense), Net Other income (expense), net consisted of the following: Three Months Ended Sept. 30 Nine Months Ended Sept. 30 (Thousands of Dollars) 2015 2014 2015 2014 Interest income $ 38 $ 73 $ 83 $ 313 Other nonoperating income — 1 — 1 Insurance policy income (expense) 221 (8 ) 166 (336 ) Other nonoperating expense (156 ) — (46 ) — Other income (expense), net $ 103 $ 66 $ 203 $ (22 )

Benefit Plans and Other Postret

Benefit Plans and Other Postretirement Benefits	9 Months Ended
	Sep. 30, 2015
Compensation and Retirement Disclosure [Abstract]
Benefit Plans and Other Postretirement Benefits	Benefit Plans and Other Postretirement Benefits Components of Net Periodic Benefit Cost (Credit) Three Months Ended Sept. 30 2015 2014 2015 2014 (Thousands of Dollars) Pension Benefits Postretirement Health Care Benefits Service cost $ 2,752 $ 2,296 $ 239 $ 312 Interest cost 5,046 5,111 436 643 Expected return on plan assets (7,153 ) (6,545 ) (635 ) (812 ) Amortization of prior service cost (credit) 9 14 (101 ) (100 ) Amortization of net loss (gain) 3,772 3,332 (159 ) (80 ) Net periodic benefit cost (credit) 4,426 4,208 (220 ) (37 ) Credits recognized due to the effects of regulation 740 707 — — Net benefit cost (credit) recognized for financial reporting $ 5,166 $ 4,915 $ (220 ) $ (37 ) Nine Months Ended Sept. 30 2015 2014 2015 2014 (Thousands of Dollars) Pension Benefits Postretirement Health Care Benefits Service cost $ 8,255 $ 6,888 $ 716 $ 935 Interest cost 15,138 15,333 1,309 1,929 Expected return on plan assets (21,458 ) (19,635 ) (1,905 ) (2,435 ) Amortization of prior service cost (credit) 29 41 (301 ) (301 ) Amortization of net loss (gain) 11,316 9,995 (479 ) (241 ) Net periodic benefit cost (credit) 13,280 12,622 (660 ) (113 ) Credits recognized due to the effects of regulation 2,139 2,122 — — Net benefit cost (credit) recognized for financial reporting $ 15,419 $ 14,744 $ (660 ) $ (113 ) In January 2015, contributions of $90.0 million were made across four of Xcel Energy's pension plans, of which $11.6 million was attributable to SPS. Xcel Energy does not expect additional pension contributions during 2015.

Other Comprehensive Income

Other Comprehensive Income	9 Months Ended
	Sep. 30, 2015
Stockholders' Equity Note [Abstract]
Other Comprehensive Income	Other Comprehensive Income Changes in accumulated other comprehensive loss, net of tax, for the three and nine months ended Sept. 30, 2015 and 2014 were as follows: Gains and Losses on Cash Flow Hedges (Thousands of Dollars) Three Months Ended Sept. 30, 2015 Three Months Ended Sept. 30, 2014 Accumulated other comprehensive loss at July 1 $ (904 ) $ (1,076 ) Losses reclassified from net accumulated other comprehensive loss 44 44 Net current period other comprehensive income 44 44 Accumulated other comprehensive loss at Sept. 30 $ (860 ) $ (1,032 ) Gains and Losses on Cash Flow Hedges (Thousands of Dollars) Nine Months Ended Sept. 30, 2015 Nine Months Ended Sept. 30, 2014 Accumulated other comprehensive loss at Jan. 1 $ (989 ) $ (1,161 ) Losses reclassified from net accumulated other comprehensive loss 129 129 Net current period other comprehensive income 129 129 Accumulated other comprehensive loss at Sept. 30 $ (860 ) $ (1,032 ) Reclassifications from accumulated other comprehensive loss for the three and nine months ended Sept. 30, 2015 and 2014 were as follows: Amounts Reclassified from Accumulated Other Comprehensive Loss (Thousands of Dollars) Three Months Ended Sept. 30, 2015 Three Months Ended Sept. 30, 2014 Losses on cash flow hedges: Interest rate derivatives $ 68 (a) $ 68 (a) Total, pre-tax 68 68 Tax benefit (24 ) (24 ) Total amounts reclassified, net of tax $ 44 $ 44 Amounts Reclassified from Accumulated Other Comprehensive Loss (Thousands of Dollars) Nine Months Ended Sept. 30, 2015 Nine Months Ended Sept. 30, 2014 Losses on cash flow hedges: Interest rate derivatives $ 201 (a) $ 201 (a) Total, pre-tax 201 201 Tax benefit (72 ) (72 ) Total amounts reclassified, net of tax $ 129 $ 129 (a) Included in interest charges.

Selected Balance Sheet Data (Ta

Selected Balance Sheet Data (Tables)	9 Months Ended
	Sep. 30, 2015
Balance Sheet Related Disclosures [Abstract]
Accounts Receivable, Net	(Thousands of Dollars) Sept. 30, 2015 Dec. 31, 2014 Accounts receivable, net Accounts receivable $ 102,408 $ 77,465 Less allowance for bad debts (6,480 ) (5,839 ) $ 95,928 $ 71,626
Inventories	(Thousands of Dollars) Sept. 30, 2015 Dec. 31, 2014 Inventories Materials and supplies $ 25,595 $ 24,738 Fuel 14,285 18,493 $ 39,880 $ 43,231
Property, Plant and Equipment, Net	(Thousands of Dollars) Sept. 30, 2015 Dec. 31, 2014 Property, plant and equipment, net Electric plant $ 5,673,759 $ 5,376,606 Construction work in progress 338,889 238,519 Total property, plant and equipment 6,012,648 5,615,125 Less accumulated depreciation (1,951,029 ) (1,871,984 ) $ 4,061,619 $ 3,743,141

Income Taxes (Tables)

Income Taxes (Tables)	9 Months Ended
	Sep. 30, 2015
Income Tax Disclosure [Abstract]
Reconciliation of Unrecognized Tax Benefits	A reconciliation of the amount of unrecognized tax benefit is as follows: (Millions of Dollars) Sept. 30, 2015 Dec. 31, 2014 Unrecognized tax benefit — Permanent tax positions $ 1.6 $ 1.5 Unrecognized tax benefit — Temporary tax positions 12.7 11.7 Total unrecognized tax benefit $ 14.3 $ 13.2
Tax Benefits Associated with NOL and Tax Credit Carryforwards	The unrecognized tax benefit amounts were reduced by the tax benefits associated with net operating loss (NOL) and tax credit carryforwards. The amounts of tax benefits associated with NOL and tax credit carryforwards are as follows: (Millions of Dollars) Sept. 30, 2015 Dec. 31, 2014 NOL and tax credit carryforwards $ (6.3 ) $ (4.8 )

Rate Matters (Tables)

Rate Matters (Tables)	9 Months Ended
	Sep. 30, 2015
Public Utilities, General Disclosures [Abstract]
SPS' New Mexico 2015 Electric Rate Case [Table Text Block]	The major components of the requested rate increase are summarized below: (Millions of Dollars) Request 2015 base period deficiency $ 19.7 Capital expenditures — post-test year adjustments 12.3 Depreciation, higher rates reflecting changes in depreciable lives, interim retirements and net salvage 3.7 Transmission revenue and expense, including charges paid to SPP for construction of regionally shared transmission projects 2.0 ROE, reflecting an increase from 9.96 percent to 10.25 percent 1.6 Rider revenue adjustments - gross receipts tax 1.3 Other, net 4.8 Requested rate increase $ 45.4
SPS' Texas 2015 Electric Rate Case [Table Text Block]	The following table reflects the positions of Alliance of Xcel Municipalities (AXM), the Office of Public Utility Counsel (OPUC), the PUCT Staff (Staff), SPS as well as the estimated recommendation of the ALJs: SPS Rebuttal Testimony ALJs’ PFD (a) (Millions of Dollars) AXM OPUC Staff SPS’ revised rate request $ 58.9 $ 58.9 $ 58.9 $ 58.9 $ 42.1 Investment for capital expenditures — post-test year adjustments (11.3 ) (23.8 ) (23.8 ) — (16.7 ) Lower ROE (10.9 ) (13.5 ) (12.1 ) — (6.3 ) Rate base adjustments (largely the removal of the prepaid pension asset) (6.2 ) (6.8 ) — — — O&M expense adjustments (13.7 ) (11.0 ) (7.9 ) (1.6 ) (5.3 ) Depreciation expense (13.3 ) — — — (3.9 ) Property taxes — (1.2 ) (4.4 ) (1.8 ) (3.7 ) Revenue adjustments (2.2 ) (0.2 ) — — — Wholesale load reductions (13.2 ) — (11.1 ) — — Southwest Power Pool (SPP) transmission expansion plan — — — (7.3 ) (4.2 ) Other, net (1.7 ) (0.6 ) (2.2 ) (1.8 ) (0.6 ) Total recommendation $ (13.6 ) $ 1.8 $ (2.6 ) $ 46.4 $ 1.4 Adjustment to move rate case expenses to a separate docket — — — (4.3 ) (0.2 ) Recommendation, excluding rate case expenses $ (13.6 ) $ 1.8 $ (2.6 ) $ 42.1 $ 1.2 (a) The ALJs’ recommendation reflects proposed adjustments to SPS’ rebuttal testimony, as of Oct. 12, 2015, which supports a $42.1 million rate increase.

Borrowings and Other Financin24

Borrowings and Other Financing Instruments (Tables)	9 Months Ended
	Sep. 30, 2015
Borrowings and Other Financing Instruments [Abstract]
Credit Facilities	At Sept. 30, 2015 , SPS had the following committed credit facility available (in millions of dollars): Credit Facility (a) Drawn (b) Available $ 400 $ 10 $ 390 (a) This credit facility expires in October 2019. (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 Sept. 30, 2015 Twelve Months Ended Dec. 31, 2014 Borrowing limit $ 100 $ 100 Amount outstanding at period end 18 16 Average amount outstanding 47 9 Maximum amount outstanding 100 100 Weighted average interest rate, computed on a daily basis 0.41 % 0.22 % Weighted average interest rate at period end 0.38 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 Sept. 30, 2015 Twelve Months Ended Dec. 31, 2014 Borrowing limit $ 400 $ 400 Amount outstanding at period end — 37 Average amount outstanding 135 83 Maximum amount outstanding 246 241 Weighted average interest rate, computed on a daily basis 0.45 % 0.26 % Weighted average interest rate at period end N/A 0.47

Fair Value of Financial Asset25

Fair Value of Financial Assets and Liabilities (Tables)	9 Months Ended
	Sep. 30, 2015
Fair Value Disclosures [Abstract]
Gross Notional Amounts of Commodity FTRs	The following table details the gross notional amounts of commodity FTRs at Sept. 30, 2015 and Dec. 31, 2014: (Amounts in Thousands) (a) Sept. 30, 2015 Dec. 31, 2014 Megawatt hours of electricity 9,412 6,930 (a) Amounts are not reflective of net positions in the underlying commodities.
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 Sept. 30, 2015: Sept. 30, 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 $ — $ — $ 13,594 $ 13,594 $ (6,234 ) $ 7,360 Total current derivative assets $ — $ — $ 13,594 $ 13,594 $ (6,234 ) 7,360 PPAs (a) 7,892 Current derivative instruments $ 15,252 Noncurrent derivative assets PPAs (a) $ 27,245 Noncurrent derivative instruments $ 27,245 Current derivative liabilities Other derivative instruments: Electric commodity $ — $ — $ 6,234 $ 6,234 $ (6,234 ) $ — Total current derivative liabilities $ — $ — $ 6,234 $ 6,234 $ (6,234 ) — PPAs (a) 3,565 Current derivative instruments $ 3,565 Noncurrent derivative liabilities PPAs (a) $ 27,969 Noncurrent derivative instruments $ 27,969 (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 Sept. 30, 2015. At Sept. 30, 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 for each of the fair value hierarchy levels, SPS’ derivative assets and liabilities measured at fair value on a recurring basis at Dec. 31, 2014: Dec. 31, 2014 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 $ — $ — $ 25,774 $ 25,774 $ (9,890 ) $ 15,884 Total current derivative assets $ — $ — $ 25,774 $ 25,774 $ (9,890 ) 15,884 PPAs (a) 7,892 Current derivative instruments $ 23,776 Noncurrent derivative assets PPAs (a) $ 33,164 Noncurrent derivative instruments $ 33,164 Current derivative liabilities Other derivative instruments: Electric commodity $ — $ — $ 9,890 $ 9,890 $ (9,890 ) $ — Total current derivative liabilities $ — $ — $ 9,890 $ 9,890 $ (9,890 ) — PPAs (a) 3,565 Current derivative instruments $ 3,565 Noncurrent derivative liabilities PPAs (a) $ 30,643 Noncurrent derivative instruments $ 30,643 (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, 2014. At Dec. 31, 2014, 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 three and nine months ended Sept. 30, 2015 and 2014: Three Months Ended Sept. 30 (Thousands of Dollars) 2015 2014 Balance at July 1 $ 11,463 $ 33,942 Purchases 408 4,429 Settlements (7,409 ) (8,346 ) Net transactions recorded during the period: Gains (losses) recognized as regulatory assets and liabilities 2,898 (7,785 ) Balance at Sept. 30 $ 7,360 $ 22,240 Nine Months Ended Sept. 30 (Thousands of Dollars) 2015 2014 Balance at Jan. 1 $ 15,884 $ 9,933 Purchases 22,621 43,904 Settlements (25,810 ) (23,001 ) Net transactions recorded during the period: Losses recognized as regulatory assets and liabilities (5,335 ) (8,596 ) Balance at Sept. 30 $ 7,360 $ 22,240
Carrying Amount and Fair Value of Long-term Debt	As of Sept. 30, 2015 and Dec. 31, 2014 , other financial instruments for which the carrying amount did not equal fair value were as follows: Sept. 30, 2015 Dec. 31, 2014 (Thousands of Dollars) Carrying Amount Fair Value Carrying Amount Fair Value Long-term debt, including current portion $ 1,550,537 $ 1,713,069 $ 1,349,691 $ 1,572,414

Other Income (Expense), Net (Ta

Other Income (Expense), Net (Tables)	9 Months Ended
	Sep. 30, 2015
Other Income and Expenses [Abstract]
Other Income (Expense), Net	Other income (expense), net consisted of the following: Three Months Ended Sept. 30 Nine Months Ended Sept. 30 (Thousands of Dollars) 2015 2014 2015 2014 Interest income $ 38 $ 73 $ 83 $ 313 Other nonoperating income — 1 — 1 Insurance policy income (expense) 221 (8 ) 166 (336 ) Other nonoperating expense (156 ) — (46 ) — Other income (expense), net $ 103 $ 66 $ 203 $ (22 )

Benefit Plans and Other Postr27

Benefit Plans and Other Postretirement Benefits (Tables)	9 Months Ended
	Sep. 30, 2015
Compensation and Retirement Disclosure [Abstract]
Components of Net Periodic Benefit Cost (Credit)	Components of Net Periodic Benefit Cost (Credit) Three Months Ended Sept. 30 2015 2014 2015 2014 (Thousands of Dollars) Pension Benefits Postretirement Health Care Benefits Service cost $ 2,752 $ 2,296 $ 239 $ 312 Interest cost 5,046 5,111 436 643 Expected return on plan assets (7,153 ) (6,545 ) (635 ) (812 ) Amortization of prior service cost (credit) 9 14 (101 ) (100 ) Amortization of net loss (gain) 3,772 3,332 (159 ) (80 ) Net periodic benefit cost (credit) 4,426 4,208 (220 ) (37 ) Credits recognized due to the effects of regulation 740 707 — — Net benefit cost (credit) recognized for financial reporting $ 5,166 $ 4,915 $ (220 ) $ (37 ) Nine Months Ended Sept. 30 2015 2014 2015 2014 (Thousands of Dollars) Pension Benefits Postretirement Health Care Benefits Service cost $ 8,255 $ 6,888 $ 716 $ 935 Interest cost 15,138 15,333 1,309 1,929 Expected return on plan assets (21,458 ) (19,635 ) (1,905 ) (2,435 ) Amortization of prior service cost (credit) 29 41 (301 ) (301 ) Amortization of net loss (gain) 11,316 9,995 (479 ) (241 ) Net periodic benefit cost (credit) 13,280 12,622 (660 ) (113 ) Credits recognized due to the effects of regulation 2,139 2,122 — — Net benefit cost (credit) recognized for financial reporting $ 15,419 $ 14,744 $ (660 ) $ (113 )

Other Comprehensive Income (Tab

Other Comprehensive Income (Tables)	9 Months Ended
	Sep. 30, 2015
Stockholders' Equity Note [Abstract]
Changes in Accumulated Other Comprehensive Loss, Net of Tax	Changes in accumulated other comprehensive loss, net of tax, for the three and nine months ended Sept. 30, 2015 and 2014 were as follows: Gains and Losses on Cash Flow Hedges (Thousands of Dollars) Three Months Ended Sept. 30, 2015 Three Months Ended Sept. 30, 2014 Accumulated other comprehensive loss at July 1 $ (904 ) $ (1,076 ) Losses reclassified from net accumulated other comprehensive loss 44 44 Net current period other comprehensive income 44 44 Accumulated other comprehensive loss at Sept. 30 $ (860 ) $ (1,032 ) Gains and Losses on Cash Flow Hedges (Thousands of Dollars) Nine Months Ended Sept. 30, 2015 Nine Months Ended Sept. 30, 2014 Accumulated other comprehensive loss at Jan. 1 $ (989 ) $ (1,161 ) Losses reclassified from net accumulated other comprehensive loss 129 129 Net current period other comprehensive income 129 129 Accumulated other comprehensive loss at Sept. 30 $ (860 ) $ (1,032 )
Reclassifications out of Accumulated Other Comprehensive Loss	Reclassifications from accumulated other comprehensive loss for the three and nine months ended Sept. 30, 2015 and 2014 were as follows: Amounts Reclassified from Accumulated Other Comprehensive Loss (Thousands of Dollars) Three Months Ended Sept. 30, 2015 Three Months Ended Sept. 30, 2014 Losses on cash flow hedges: Interest rate derivatives $ 68 (a) $ 68 (a) Total, pre-tax 68 68 Tax benefit (24 ) (24 ) Total amounts reclassified, net of tax $ 44 $ 44 Amounts Reclassified from Accumulated Other Comprehensive Loss (Thousands of Dollars) Nine Months Ended Sept. 30, 2015 Nine Months Ended Sept. 30, 2014 Losses on cash flow hedges: Interest rate derivatives $ 201 (a) $ 201 (a) Total, pre-tax 201 201 Tax benefit (72 ) (72 ) Total amounts reclassified, net of tax $ 129 $ 129 (a) Included in interest charges.

Selected Balance Sheet Data (De

Selected Balance Sheet Data (Details) - USD ($) $ in Thousands	Sep. 30, 2015	Dec. 31, 2014
Accounts receivable, net
Accounts receivable	$ 102,408	$ 77,465
Less allowance for bad debts	(6,480)	(5,839)
Accounts receivable, net	$ 95,928	$ 71,626

Selected Balance Sheet Data Bal

Selected Balance Sheet Data Balance Sheet Related Disclosures, Inventories (Details) - USD ($) $ in Thousands	Sep. 30, 2015	Dec. 31, 2014
Public Utilities, Inventory [Line Items]
Inventories	$ 39,880	$ 43,231
Materials and supplies
Public Utilities, Inventory [Line Items]
Inventories	25,595	24,738
Fuel
Public Utilities, Inventory [Line Items]
Inventories	$ 14,285	$ 18,493

Selected Balance Sheet Data B31

Selected Balance Sheet Data Balance Sheet Related Disclosures, Property, Plant and Equipment (Details) - USD ($) $ in Thousands	Sep. 30, 2015	Dec. 31, 2014
Public Utility, Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	$ 6,012,648	$ 5,615,125
Less accumulated depreciation	(1,951,029)	(1,871,984)
Property, plant and equipment, net	4,061,619	3,743,141
Electric plant
Public Utility, Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	5,673,759	5,376,606
Construction work in progress
Public Utility, Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	$ 338,889	$ 238,519

Income Taxes (Details)

Income Taxes (Details) - USD ($)	3 Months Ended	9 Months Ended
	Sep. 30, 2012	Sep. 30, 2015	Dec. 31, 2014
Unrecognized Tax Benefits [Abstract]
Unrecognized tax benefit - Permanent tax positions		$ 1,600,000	$ 1,500,000
Unrecognized tax benefit - Temporary tax positions		12,700,000	11,700,000
Total unrecognized tax benefit		14,300,000	13,200,000
NOL and tax credit carryforwards		(6,300,000)	$ (4,800,000)
Upper bound of decrease in unrecognized tax benefit that is reasonably possible		2,000,000
Amounts accrued for penalties related to unrecognized tax benefits		$ 0
Internal Revenue Service (IRS)
Tax Audits [Abstract]
Year(s) under examination	2010 and 2011	2012 and 2013
Year of carryback claim under examination	2,009
Potential Tax Adjustments		$ 13,000,000
State Jurisdiction (Texas)
Tax Audits [Abstract]
Earliest year subject to examination		2,009

Rate Matters (Details)

Rate Matters (Details) $ in Thousands		Oct. 29, 2015USD ($)	Oct. 28, 2015USD ($)	Oct. 12, 2015USD ($)	Oct. 31, 2015USD ($)	Aug. 31, 2015USD ($)	Jun. 30, 2015USD ($)		May. 31, 2015USD ($)	Mar. 31, 2015USD ($)	Jan. 31, 2015	Dec. 31, 2014USD ($)	Oct. 31, 2014	Dec. 31, 2013USD ($)	Aug. 31, 2013Factor	Jul. 31, 2013	Mar. 31, 2013	Apr. 30, 2012	Sep. 30, 2015USD ($)
Public Utilities, General Disclosures [Line Items]
Other Liabilities, Current												$ 80,211							$ 96,378
Texas 2015 Electric Rate Case
Public Utilities, General Disclosures [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount							$ 42,100	[1]				$ 64,800
Public Utilities, Requested Rate Increase (Decrease), Percentage							4.40%					6.70%
Public Utilities, Requested Return on Equity, Percentage												10.25%
Public Utilities, Requested Rate Base, Amount												$ 1,600,000
Public Utilities, Requested Equity Capital Structure, Percentage												53.97%
Public Utilities, Revised Requested Rate Increase										$ 58,900
Public Utilities, Additional Capital Investment												$ 392,000
Public Utilities, Post Test Year Decrease Adjustments							$ 0
Public Utilities, Decrease To Requested Return On Equity							0
Public Utilities, Decrease To Rate Base							0
Public Utilities, Decrease To O&M Expenses							(1,600)
Public Utilities, Decrease To Depreciation Expense							0
Public Utilities, Decrease To Property Taxes							(1,800)
Public Utilities, Decrease To Revenue Adjustments							0
Public Utilities, Decrease To Wholesale Load Reductions							0
Public Utilities, Decrease To Transmission Expansion plan							(7,300)
Public Utilities, Decrease Related To Other, Net							(1,800)
Public Utilities, Requested Rate Increase (Including Case Expenses), Amount							46,400
Public Utilities, Decrease Adjustment To Move Rate Case Expenses To Separate Docket							$ (4,300)
Global Settlement Agreement [Member]
Public Utilities, General Disclosures [Line Items]
Number Of Customers For Which A Public Utility Proposes To Revise Formula Rates						4
Public Utilities, Disclosure Of Regulatory Matters Pending						9
Public Utilities, Number Of Coincident Peaks Used As Demand Allocator, Revised						3
Public Utilities, Base Return On Equity Charged To Customers Through Transmission Formula Rates, Percentage						10.50%
Public Utilities, Incremental ROE Basis Point Increase						50
Public Utilities, Base Return On Equity Charged To Customers Through Production Formula Rates, Percentage						10.00%
Number Of Coincident Peaks Utilized As Demand Allocator						12
Number Of Coincident Peaks Used As Demand Allocator, Original															12
Number Of Days Until Settlement Agreement Effective After Approval						30 days
Federal Energy Regulatory Commission (FERC) Orders [Member]
Public Utilities, General Disclosures [Line Items]
Number Of Customers For Which A Public Utility Proposes To Revise Formula Rates											4
Number Of Coincident Peaks Used As Demand Allocator, Original											12
Number Of Components Included In Regulatory Proceeding | Factor															2
Current Year Pre-tax Earnings Impact Of Regulatory Proceedings																			$ 1,900
Wholesale Electric Rate Complaints [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Base Return On Equity Charged To Customers Through Transmission Formula Rates, Percentage																		11.27%
Public Utilities, Base Return On Equity Charged To Customers Through Production Formula Rates, Percentage																		10.25%
Public Utilities, Base Return On Equity Requested Charged To Customers Through Production Formula Rates, Percentage													8.61%			9.15%		9.15%
Public Utilities, Base Return On Equity Requested By Customers To Be Charged Through Transmission Formula Rates, Percentage													9.11%			9.65%		9.65%
Golden Spread [Member] | Global Settlement Agreement [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Regulatory Settlement To Be Paid						$ 44,900
Public Service Company of New Mexico [Member] | Global Settlement Agreement [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Regulatory Settlement To Be Paid						$ 4,200
Alliance of Xcel Municipalities [Member] | Texas 2015 Electric Rate Case
Public Utilities, General Disclosures [Line Items]
Public Utilities, Revised Requested Rate Increase										58,900
Public Utilities, Recommended Rate Increase (Decrease), Amount									$ (13,600)
Public Utilities, Post Test Year Decrease Adjustments									(11,300)
Public Utilities, Decrease To Requested Return On Equity									(10,900)
Public Utilities, Decrease To Rate Base									(6,200)
Public Utilities, Decrease To O&M Expenses									(13,700)
Public Utilities, Decrease To Depreciation Expense									(13,300)
Public Utilities, Decrease To Property Taxes									0
Public Utilities, Decrease To Revenue Adjustments									(2,200)
Public Utilities, Decrease To Wholesale Load Reductions									(13,200)
Public Utilities, Decrease To Transmission Expansion plan									0
Public Utilities, Decrease Related To Other, Net									(1,700)
Public Utilities, Recommended Rate Increase (Decrease) (Including Case Expenses)									(13,600)
Public Utilities, Decrease Adjustment To Move Rate Case Expenses To Separate Docket									0
Federal Energy Regulatory Commission (FERC) | Federal Energy Regulatory Commission (FERC) Orders [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Number Of Coincident Peaks Used As Demand Allocator, Revised															3
Number Of Coincident Peaks Used As Demand Allocator, Original															12
Other Liabilities, Current												$ 50,400
Office of Public Utility Counsel [Member] | Texas 2015 Electric Rate Case
Public Utilities, General Disclosures [Line Items]
Public Utilities, Revised Requested Rate Increase										58,900
Public Utilities, Recommended Rate Increase (Decrease), Amount									1,800
Public Utilities, Post Test Year Decrease Adjustments									(23,800)
Public Utilities, Decrease To Requested Return On Equity									(13,500)
Public Utilities, Decrease To Rate Base									(6,800)
Public Utilities, Decrease To O&M Expenses									(11,000)
Public Utilities, Decrease To Depreciation Expense									0
Public Utilities, Decrease To Property Taxes									(1,200)
Public Utilities, Decrease To Revenue Adjustments									(200)
Public Utilities, Decrease To Wholesale Load Reductions									0
Public Utilities, Decrease To Transmission Expansion plan									0
Public Utilities, Decrease Related To Other, Net									(600)
Public Utilities, Recommended Rate Increase (Decrease) (Including Case Expenses)									1,800
Public Utilities, Decrease Adjustment To Move Rate Case Expenses To Separate Docket									0
Public Utility Commission of Texas Staff [Member] | Texas 2015 Electric Rate Case
Public Utilities, General Disclosures [Line Items]
Public Utilities, Revised Requested Rate Increase										$ 58,900
Public Utilities, Recommended Rate Increase (Decrease), Amount									(2,600)
Public Utilities, Post Test Year Decrease Adjustments									(23,800)
Public Utilities, Decrease To Requested Return On Equity									(12,100)
Public Utilities, Decrease To Rate Base									0
Public Utilities, Decrease To O&M Expenses									(7,900)
Public Utilities, Decrease To Depreciation Expense									0
Public Utilities, Decrease To Property Taxes									(4,400)
Public Utilities, Decrease To Revenue Adjustments									0
Public Utilities, Decrease To Wholesale Load Reductions									(11,100)
Public Utilities, Decrease To Transmission Expansion plan									0
Public Utilities, Decrease Related To Other, Net									(2,200)
Public Utilities, Recommended Rate Increase (Decrease) (Including Case Expenses)									(2,600)
Public Utilities, Decrease Adjustment To Move Rate Case Expenses To Separate Docket									$ 0
Subsequent Event | New Mexico 2015 Electric Rate Case [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Approved Return on Equity, Percentage					9.96%
Public Utilities, Requested Rate Increase (Decrease), Amount					$ 45,400
Public Utilities, Requested Return on Equity, Percentage					10.25%
Public Utilities, Requested Rate Base, Amount					$ 734,000
Public Utilities, Requested Equity Capital Structure, Percentage					53.97%
Public Utilities, Net Requested Increase Base Rates, Amount					$ 24,300
Public Utilities, Decrease In Base Fuel Revenues					21,100
Public Utilities, Base Period Deficiency					19,700
Public Utilities, Post Test Year Adjustment Related to Capital Expenditures					12,300
Public Utilities, Depreciation Expense					3,700
Public Utilities, SPP Transmission Expansion Plan					2,000
Public Utilities, ROE					1,600
Public Utilities, Rider Costs To Be Recovered Through Base Rates, Amount					1,300
Public Utilities, Other Net					$ 4,800
Subsequent Event | Global Settlement Agreement [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Estimated Net Gain Expected To Be Recognized		$ 7,900
Subsequent Event | Administrative Law Judge [Member] | Texas 2015 Electric Rate Case
Public Utilities, General Disclosures [Line Items]
Public Utilities, Recommended Rate Increase (Decrease), Amount	[1]			$ 1,200
Public Utilities, Recommended Return On Equity, Percentage				9.70%
Public Utilities, Recommended Equity Capital Structure, Percentage				53.97%
Public Utilities, Post Test Year Decrease Adjustments	[1]			$ (16,700)
Public Utilities, Decrease To Requested Return On Equity	[1]			(6,300)
Public Utilities, Decrease To Rate Base	[1]			0
Public Utilities, Decrease To O&M Expenses	[1]			(5,300)
Public Utilities, Decrease To Depreciation Expense	[1]			(3,900)
Public Utilities, Decrease To Property Taxes	[1]			(3,700)
Public Utilities, Decrease To Revenue Adjustments	[1]			0
Public Utilities, Decrease To Wholesale Load Reductions	[1]			0
Public Utilities, Decrease To Transmission Expansion plan	[1]			(4,200)
Public Utilities, Decrease Related To Other, Net	[1]			(600)
Public Utilities, Recommended Rate Increase (Decrease) (Including Case Expenses)	[1]			1,400
Public Utilities, Decrease Adjustment To Move Rate Case Expenses To Separate Docket	[1]			$ (200)
Public Utilities, Revised Recommended Rate Increase (Decrease), Amount			$ 14,400
Certain Texas Transmission Assets [Member] | Federal Energy Regulatory Commission (FERC)
Public Utilities, General Disclosures [Line Items]
Current Year Pre-tax Earnings Impact Of Regulatory Proceedings														$ 13,600
Public Utilities, Number Of Substations Included In Purchase And Sale Agreement																	2
Proceeds From Sale Of Other Property, Plant, And Equipment														37,100
Public Utilities, Regulatory Liabilities Recognized For Jurisdictional Gain Sharing														$ 7,200
[1]	The ALJs’ recommendation reflects proposed adjustments to SPS’ rebuttal testimony, as of Oct. 12, 2015, which supports a $42.1 million rate increase.

Commitments and Contingencies,

Commitments and Contingencies, Purchased Power Agreements (Details) - Independent Power Producing Entities - MW	9 Months Ended	12 Months Ended
	Sep. 30, 2015	Dec. 31, 2014
Purchased Power Agreements [Abstract]
Generating capacity (in MW)	827	827
Purchase Power Agreement Duration, Maximum (year)	2,033	2,033

Commitments and Contingencies35

Commitments and Contingencies, Environmental Contingencies - Unrecorded Unconditional Purchase Obligation (Details) $ in Millions	1 Months Ended			9 Months Ended
	Oct. 31, 2015	Dec. 31, 2014	Apr. 30, 2012MW	Sep. 30, 2015USD ($)MW	Oct. 30, 2015Period	Apr. 30, 2015USD ($)	Apr. 30, 2014Issue
Cross-State Air Pollution Rule
Environmental Requirements [Abstract]
Number of issues on which the D.C. Circuit overturned the CSAPR | Issue							2
Generating capacity (in MW) | MW				700
Electric Generating Unit Mercury and Air Toxics Standards Rule
Environmental Requirements [Abstract]
Generating capacity (in MW) | MW			25
Cost of capital incurred for installed mercury controls						$ 8
Regional Haze Rules
Environmental Requirements [Abstract]
Number of years to comply with proposed regulation		5 years
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
Number of months in which the state would have to submit an implementation plan for the respective nonattainment areas				18 months
Number of years for the state to achieve the designated attainment standard				5 years
Number of units which sulfur dioxide controls could be required				1
Capital Addition Purchase Commitments | Regional Haze Rules
Environmental Requirements [Abstract]
Liability for estimated cost to comply with regulation				$ 600
Estimated annual operating cost to comply with proposed regulation				$ 10.4
Subsequent Event | Green House Gas Emission Standard for Existing Sources
Environmental Requirements [Abstract]
Duration for public comment (in days)	90 days
Percentage of a comparable new plant's capital cost which would have to be exceeded to consider a project as a reconstruction under the proposed GHG NSPS for Modified and Reconstructed Power Plants	50.00%
Subsequent Event | National Ambient Air Quality Standards for Ozone
Environmental Requirements [Abstract]
Number of hours measured for standard | Period					8
Current level of air quality concentrations (in parts per billion)					75
Proposed level of air quality concentrations (in parts per billion)					70
Maximum | Electric Generating Unit Mercury and Air Toxics Standards Rule
Environmental Requirements [Abstract]
Number of years before affected facilities must demonstrate compliance			4 years
Minimum | Electric Generating Unit Mercury and Air Toxics Standards Rule
Environmental Requirements [Abstract]
Number of years before affected facilities must demonstrate compliance			3 years

Borrowings and Other Financin36

Borrowings and Other Financing Instruments, Short-Term Borrowings (Details) - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Sep. 30, 2015	Dec. 31, 2014
Short-term Debt [Line Items]
Amount outstanding at period end	$ 0	$ 37,000
Money Pool
Short-term Debt [Line Items]
Borrowing limit	100,000	100,000
Amount outstanding at period end	18,000	16,000
Average amount outstanding	47,000	9,000
Maximum amount outstanding	$ 100,000	$ 100,000
Weighted average interest rate, computed on a daily basis (percentage)	0.41%	0.22%
Weighted average interest rate at period end (percentage)	0.38%	0.45%
Commercial Paper
Short-term Debt [Line Items]
Borrowing limit	$ 400,000	$ 400,000
Amount outstanding at period end	0	37,000
Average amount outstanding	135,000	83,000
Maximum amount outstanding	$ 246,000	$ 241,000
Weighted average interest rate, computed on a daily basis (percentage)	0.45%	0.26%
Weighted average interest rate at period end (percentage)		0.47%

Borrowings and Other Financin37

Borrowings and Other Financing Instruments, Letters of Credit (Details) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2015	Dec. 31, 2014
Line of Credit Facility [Line Items]
Amount outstanding at period end	$ 0	$ 37,000
Letter of Credit
Line of Credit Facility [Line Items]
Amount outstanding at period end	$ 10,000	$ 30,000
Letter of Credit | Letter of Credit
Line of Credit Facility [Line Items]
Term of letters of credit (in years)	1 year

Borrowings and Other Financin38

Borrowings and Other Financing Instruments, Credit Facility (Details) - Credit Facility - USD ($)		Sep. 30, 2015	Dec. 31, 2014
Line of Credit Facility [Line Items]
Credit Facility	[1]	$ 400,000,000
Drawn	[2]	10,000,000
Available		390,000,000
Direct advances on the credit facility outstanding		$ 0	$ 0
[1]	This credit facility expires in October 2019.
[2]	Includes outstanding commercial paper and letters of credit.

Borrowings and Other Financin39

Borrowings and Other Financing Instruments Borrowings and Other Financing Instruments, Long-Term Borrowings (Details) - SPS - Bonds [Member] - Series Due June 15, 2024 [Member] $ in Millions	Sep. 30, 2015USD ($)
Debt Instrument [Line Items]
Debt Instrument, Face Amount	$ 200
Debt Instrument, Interest Rate, Stated Percentage	3.30%

Fair Value of Financial Asset40

Fair Value of Financial Assets and Liabilities, Derivative Instruments (Details) MWh in Thousands, $ in Millions		Sep. 30, 2015USD ($)MWhCounterparty	Dec. 31, 2014MWh
Credit Concentration Risk
Consideration of Credit Risk and Concentrations [Abstract]
Number of most significant counterparties for wholesale, trading and non-trading commodity activities with credit exposure | Counterparty		9
Credit Concentration Risk | External Credit Rating, Investment Grade [Member]
Consideration of Credit Risk and Concentrations [Abstract]
Number of most significant counterparties for wholesale, trading and non-trading commodity activities with credit exposure | Counterparty		1
Wholesale, trading and non-trading commodity credit exposure for the most significant counterparties		$ 2.7
Percentage of wholesale, trading and non-trading commodity credit exposure for the most significant counterparties (in hundredths)		3.00%
Credit Concentration Risk | No Investment Grade Ratings from External Credit Rating Agencies
Consideration of Credit Risk and Concentrations [Abstract]
Number of most significant counterparties for wholesale, trading and non-trading commodity activities with credit exposure | Counterparty		7
Wholesale, trading and non-trading commodity credit exposure for the most significant counterparties		$ 54.8
Percentage of wholesale, trading and non-trading commodity credit exposure for the most significant counterparties (in hundredths)		53.00%
Credit Concentration Risk | Credit Quality Less Than Investment Grade [Member]
Consideration of Credit Risk and Concentrations [Abstract]
Wholesale, trading and non-trading commodity credit exposure for the most significant counterparties		$ 0.1
Percentage of wholesale, trading and non-trading commodity credit exposure for the most significant counterparties (in hundredths)		1.00%
Interest Rate Swap
Interest Rate Derivatives [Abstract]
Amount of accumulated other comprehensive losses related to interest rate derivatives expected to be reclassified into earnings within the next twelve months		$ (0.2)
Electric Commodity (in megawatt hours)
Gross Notional Amounts of Commodity FTRs [Abstract]
Derivative, Nonmonetary Notional amount | MWh	[1]	9,412	6,930
[1]	(a) Amounts are not reflective of net positions in the underlying commodities.

Fair Value of Financial Asset41

Fair Value of Financial Assets and Liabilities, Impact of Derivative Activity (Details) - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Financial Impact of Qualifying Fair Value Hedges on Earnings [Abstract]
Derivative instruments designated as fair value hedges	$ 0	$ 0	$ 0	$ 0
Recognized gains (losses) from fair value hedges or related hedged transactions	0	0	0	0
Cash Flow Hedges | Interest Rate
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract]
Pre-tax losses reclassified into income during the period from accumulated other comprehensive loss	100,000	100,000	200,000	200,000
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 losses recognized during the period in regulatory assets and liabilities	(700,000)	(1,200,000)	(2,700,000)	(3,600,000)
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities)	$ 700,000	$ 1,200,000	$ 2,300,000	$ 300,000

Fair Value of Financial Asset42

Fair Value of Financial Assets and Liabilities, Fair Value Measurements (Details) - USD ($)	Sep. 30, 2015		Dec. 31, 2014
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	15,252,000		23,776,000
Other Noncurrent Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	27,245,000		33,164,000
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	27,969,000		30,643,000
Fair Value Measured on a Recurring Basis | Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	7,360,000		15,884,000
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	7,360,000		15,884,000
Fair Value Measured on a Recurring Basis | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	0		0
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
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	13,594,000		25,774,000
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	13,594,000		25,774,000
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	6,234,000		9,890,000
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	6,234,000		9,890,000
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	13,594,000		25,774,000
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Assets | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	13,594,000		25,774,000
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	6,234,000		9,890,000
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Liabilities | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	6,234,000		9,890,000
Fair Value Measured on a Recurring Basis | Netting | Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	(6,234,000)	[1]	(9,890,000)	[2]
Fair Value Measured on a Recurring Basis | Netting | Other Current Assets | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	(6,234,000)	[1]	(9,890,000)	[2]
Fair Value Measured on a Recurring Basis | Netting | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	(6,234,000)	[1]	(9,890,000)	[2]
Fair Value Measured on a Recurring Basis | Netting | Other Current Liabilities | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	(6,234,000)	[1]	(9,890,000)	[2]
Fair Value, Measurements, Nonrecurring | Other Current Assets | Purchased Power Agreements
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	7,892,000	[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	27,245,000	[3]	33,164,000	[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	$ 27,969,000	[3]	$ 30,643,000	[4]
[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 Sept. 30, 2015. At Sept. 30, 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.
[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, 2014. At Dec. 31, 2014, 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 Asset43

Fair Value of Financial Assets and Liabilities Fair Value of Financial Assets and Liabilities, Changes in Level 3 Commodity Derivatives (Details) - Commodity Contract - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Balance at beginning of period	$ 11,463,000	$ 33,942,000	$ 15,884,000	$ 9,933,000
Purchases	408,000	4,429,000	22,621,000	43,904,000
Settlements	(7,409,000)	(8,346,000)	(25,810,000)	(23,001,000)
(Losses) gains recognized as regulatory assets and liabilities	2,898,000	(7,785,000)	(5,335,000)	(8,596,000)
Balance at end of period	7,360,000	22,240,000	7,360,000	22,240,000
Transfers into Level 3	0	0	0	0
Transfers out of Level 3	$ 0	$ 0	$ 0	$ 0

Fair Value of Financial Asset44

Fair Value of Financial Assets and Liabilities, Fair Value of Long-Term Debt (Details) - USD ($) $ in Thousands	Sep. 30, 2015	Dec. 31, 2014
Carrying Amount
Financial Liabilities, Balance Sheet Groupings [Abstract]
Long-term debt, including current portion	$ 1,550,537	$ 1,349,691
Fair Value
Financial Liabilities, Balance Sheet Groupings [Abstract]
Long-term debt, including current portion	$ 1,713,069	$ 1,572,414

Other Income (Expense), Net (De

Other Income (Expense), Net (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Other Income and Expenses [Abstract]
Interest income	$ 38	$ 73	$ 83	$ 313
Other nonoperating income	0	1	0	1
Insurance policy income (expense)	221	(8)	166	(336)
Other nonoperating expense	(156)	0	(46)	0
Other income (expense), net	$ 103	$ 66	$ 203	$ (22)

Benefit Plans and Other Postr46

Benefit Plans and Other Postretirement Benefits (Details) $ in Thousands	1 Months Ended	3 Months Ended		9 Months Ended
	Jan. 31, 2015USD ($)Plan	Sep. 30, 2015USD ($)	Sep. 30, 2014USD ($)	Sep. 30, 2015USD ($)	Sep. 30, 2014USD ($)
Pension Benefits
Components of Net Periodic Benefit Cost (Credit) [Abstract]
Service cost		$ 2,752	$ 2,296	$ 8,255	$ 6,888
Interest cost		5,046	5,111	15,138	15,333
Expected return on plan assets		(7,153)	(6,545)	(21,458)	(19,635)
Amortization of prior service cost (credit)		9	14	29	41
Amortization of net loss (gain)		3,772	3,332	11,316	9,995
Net periodic benefit cost (credit)		4,426	4,208	13,280	12,622
Defined Benefit Plan Regulatory Adjustments		740	707	2,139	2,122
Net benefit cost (credit) recognized for financial reporting		5,166	4,915	15,419	14,744
Total contributions to the pension plans during the period	$ 11,600
Postretirement Health Care Benefits
Components of Net Periodic Benefit Cost (Credit) [Abstract]
Service cost		239	312	716	935
Interest cost		436	643	1,309	1,929
Expected return on plan assets		(635)	(812)	(1,905)	(2,435)
Amortization of prior service cost (credit)		(101)	(100)	(301)	(301)
Amortization of net loss (gain)		(159)	(80)	(479)	(241)
Net periodic benefit cost (credit)		(220)	(37)	(660)	(113)
Defined Benefit Plan Regulatory Adjustments		0	0	0	0
Net benefit cost (credit) recognized for financial reporting		$ (220)	$ (37)	$ (660)	$ (113)
Xcel Energy Inc. | Pension Benefits
Components of Net Periodic Benefit Cost (Credit) [Abstract]
Total contributions to the pension plans during the period	$ 90,000
Number of Xcel Energy's pension plans to which contributions were made | Plan	4

Other Comprehensive Income (Det

Other Comprehensive Income (Details) - USD ($) $ in Thousands		3 Months Ended		9 Months Ended
		Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Accumulated other comprehensive loss at beginning of period				$ (989)
Accumulated other comprehensive loss at end of period		$ (860)		(860)
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Total, pre-tax		(98,689)	$ (103,349)	(165,413)	$ (176,294)
Tax benefit		36,874	36,412	60,775	62,587
Gains and Losses on Cash Flow Hedges
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Accumulated other comprehensive loss at beginning of period		(904)	(1,076)	(989)	(1,161)
Losses reclassified from net accumulated other comprehensive loss		44	44	129	129
Net current period other comprehensive income		44	44	129	129
Accumulated other comprehensive loss at end of period		(860)	(1,032)	(860)	(1,032)
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		68	68	201	201
Tax benefit		(24)	(24)	(72)	(72)
Total, net of tax		44	44	129	129
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]	$ 68	$ 68	$ 201	$ 201
[1]	Included in interest charges.