10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549

FORM 10-Q

(Mark One)

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2015

or

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission File Number: 001-03789

Southwestern Public Service Company

(Exact name of registrant as specified in its charter)

New Mexico	75-0575400
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
Tyler at Sixth
Amarillo, Texas	79101
(Address of principal executive offices)	(Zip Code)

(303) 571-7511

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.   x Yes ¨ No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 and Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  x Yes ¨ No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company.  See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer ¨	Accelerated filer ¨
Non-accelerated filer x	Smaller reporting company ¨
(Do not check if smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). ¨ Yes x No

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.

Class	Outstanding at Aug. 3, 2015
Common Stock, $1 par value	100 shares

Southwestern Public Service Company meets the conditions set forth in General Instruction H (1)(a) and (b) of Form 10-Q and is therefore filing this Form 10-Q with the reduced disclosure format specified in General Instruction H (2) to such Form 10-Q.

TABLE OF CONTENTS

PART I — FINANCIAL INFORMATION
Item l     —	Financial Statements (Unaudited)	3
Item 2    —	Management’s Discussion and Analysis of Financial Condition and Results of Operations	21
Item 4    —	Controls and Procedures	23
PART II — OTHER INFORMATION
Item 1     —	Legal Proceedings	23
Item 1A  —	Risk Factors	23
Item 4    —	Mine Safety Disclosures	23
Item 5    —	Other Information	23
Item 6    —	Exhibits	24
SIGNATURES		25
Certifications Pursuant to Section 302		1
Certifications Pursuant to Section 906		1
Statement Pursuant to Private Litigation		1

This Form 10-Q is filed by Southwestern Public Service Company, a New Mexico corporation (SPS). SPS is a wholly owned subsidiary of Xcel Energy Inc.  Xcel Energy Inc. wholly owns the following subsidiaries: Northern States Power Company, a Minnesota corporation (NSP-Minnesota); Northern States Power Company, a Wisconsin corporation (NSP-Wisconsin); Public Service Company of Colorado, a Colorado corporation (PSCo); and SPS.  NSP-Minnesota, NSP-Wisconsin, PSCo and SPS are also referred to collectively as utility subsidiaries.  Additional information on Xcel Energy Inc. and its subsidiaries (collectively, Xcel Energy) is available on various filings with the Securities and Exchange Commission (SEC).

2

PART 1 — FINANCIAL INFORMATION

Item 1 — FINANCIAL STATEMENTS

SOUTHWESTERN PUBLIC SERVICE COMPANY

STATEMENTS OF INCOME (UNAUDITED)

(amounts in thousands)

	Three Months Ended June 30						Six Months Ended June 30
	2015			2014			2015			2014
Operating revenues	$	422,985		$	492,536		$	846,814		$	940,936
Operating expenses
Electric fuel and purchased power	243,026			314,146			488,825			603,350
Operating and maintenance expenses	73,827			68,963			147,724			138,361
Demand side management program expenses	2,760			2,849			6,429			5,913
Depreciation and amortization	36,750			35,071			72,489			65,583
Taxes (other than income taxes)	13,490			12,507			28,456			26,153
Total operating expenses	369,853			433,536			743,923			839,360
Operating income	53,132			59,000			102,891			101,576
Other income (expense), net	156			(129		)	100			(88		)
Allowance for funds used during construction — equity	1,788			2,895			3,493			6,535
Interest charges and financing costs
Interest charges — includes other financing costs of $771, $731, $1,544 and $1,461, respectively	21,074			19,645			41,958			38,926
Allowance for funds used during construction — debt	(1,137		)	(1,721		)	(2,198		)	(3,848		)
Total interest charges and financing costs	19,937			17,924			39,760			35,078
Income before income taxes	35,139			43,842			66,724			72,945
Income taxes	12,563			15,807			23,901			26,175
Net income	$	22,576		$	28,035		$	42,823		$	46,770

See Notes to Financial Statements

3

SOUTHWESTERN PUBLIC SERVICE COMPANY

STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

(amounts in thousands)

	Three Months Ended June 30				Six Months Ended June 30
	2015		2014		2015		2014
Net income	$	22,576	$	28,035	$	42,823	$	46,770
Other comprehensive income
Derivative instruments:
Reclassification of losses to net income, net of tax of $24 and $48 for each of the three and six months ended June 30, 2015 and 2014, respectively	43		42		85		85
Other comprehensive income	43		42		85		85
Comprehensive income	$	22,619	$	28,077	$	42,908	$	46,855

See Notes to Financial Statements

4

SOUTHWESTERN PUBLIC SERVICE COMPANY

STATEMENTS OF CASH FLOWS (UNAUDITED)

(amounts in thousands)

	Six Months Ended June 30
	2015			2014
Operating activities
Net income	$	42,823		$	46,770
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	73,628			66,692
Demand side management program amortization	837			837
Deferred income taxes	11,866			51,678
Amortization of investment tax credits	(170		)	(170		)
Allowance for equity funds used during construction	(3,493		)	(6,535		)
Net derivative losses	133			133
Changes in operating assets and liabilities:
Accounts receivable	(19,478		)	(15,131		)
Accrued unbilled revenues	10,927			(33,034		)
Inventories	10,776			2,022
Prepayments and other	(21,378		)	(12,786		)
Accounts payable	(10,210		)	16,949
Net regulatory assets and liabilities	41,291			(34,055		)
Other current liabilities	13,510			1,536
Pension and other employee benefit obligations	(10,435		)	(3,122		)
Change in other noncurrent assets	607			3,558
Change in other noncurrent liabilities	606			2,198
Net cash provided by operating activities	141,840			87,540
Investing activities
Utility capital/construction expenditures	(280,615		)	(281,398		)
Allowance for equity funds used during construction	3,493			6,535
Investments in utility money pool arrangement	(9,000		)	(22,000		)
Repayments from utility money pool arrangement	9,000			22,000
Net cash used in investing activities	(277,122		)	(274,863		)
Financing activities
Proceeds from (repayment of) short-term borrowings, net	172,000			15,000
(Repayment of) proceeds from issuance of long-term debt	(85		)	148,510
Borrowings under utility money pool arrangement	163,700			382,000
Repayments under utility money pool arrangement	(179,700		)	(420,000		)
Capital contributions from parent	34,535			100,000
Dividends paid to parent	(53,167		)	(36,264		)
Net cash provided by financing activities	137,283			189,246
Net change in cash and cash equivalents	2,001			1,923
Cash and cash equivalents at beginning of period	596			1,011
Cash and cash equivalents at end of period	$	2,597		$	2,934
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	(38,527	)	$	(33,668	)
Cash (paid) received for income taxes, net	(36,992		)	8,705
Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable	$	26,513		$	22,423

See Notes to Financial Statements

5

SOUTHWESTERN PUBLIC SERVICE COMPANY

BALANCE SHEETS (UNAUDITED)

(amounts in thousands, except share and per share data)

	June 30, 2015			Dec. 31, 2014
Assets
Current assets
Cash and cash equivalents	$	2,597		$	596
Accounts receivable, net	78,386			71,626
Accounts receivable from affiliates	14,701			1,983
Accrued unbilled revenues	118,360			129,287
Inventories	32,455			43,231
Regulatory assets	36,554			52,006
Derivative instruments	19,355			23,776
Deferred income taxes	91,672			51,854
Prepayments and other	52,854			31,476
Total current assets	446,934			405,835
Property, plant and equipment, net	3,948,839			3,743,141
Other assets
Regulatory assets	308,519			323,305
Derivative instruments	29,218			33,164
Other	14,918			15,859
Total other assets	352,655			372,328
Total assets	$	4,748,428		$	4,521,304
Liabilities and Equity
Current liabilities
Short-term debt	$	209,000		$	37,000
Borrowings under utility money pool arrangement	—			16,000
Accounts payable	148,722			160,762
Accounts payable to affiliates	14,970			19,790
Regulatory liabilities	115,316			87,723
Taxes accrued	24,017			27,208
Accrued interest	17,071			17,057
Dividends payable	23,025			27,828
Derivative instruments	3,565			3,565
Other	90,838			80,211
Total current liabilities	646,524			477,144
Deferred credits and other liabilities
Deferred income taxes	899,063			849,145
Regulatory liabilities	105,051			115,188
Asset retirement obligations	26,713			26,031
Derivative instruments	28,860			30,643
Pension and employee benefit obligations	93,166			103,670
Other	9,643			9,320
Total deferred credits and other liabilities	1,162,496			1,133,997
Commitments and contingencies
Capitalization
Long-term debt	1,349,858			1,349,691
Common stock — 200 shares authorized of $1.00 par value; 100 shares outstanding at June 30, 2015 and Dec. 31, 2014, respectively	—			—
Additional paid in capital	1,199,998			1,165,463
Retained earnings	390,456			395,998
Accumulated other comprehensive loss	(904		)	(989		)
Total common stockholder’s equity	1,589,550			1,560,472
Total liabilities and equity	$	4,748,428		$	4,521,304

See Notes to Financial Statements

6

SOUTHWESTERN PUBLIC SERVICE COMPANY

Notes to Financial Statements (UNAUDITED)

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 June 30, 2015, and Dec. 31, 2014; the results of its operations, including the components of net income and comprehensive income, for the three and six months ended June 30, 2015 and 2014; and its cash flows for the six months endedJune 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 June 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.

1. 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.

2. 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 is currently evaluating the impact of adopting ASU 2015-02 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 (Accounting Standards Update (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.

7

3. Selected Balance Sheet Data

(Thousands of Dollars)	June 30, 2015			Dec. 31, 2014
Accounts receivable, net
Accounts receivable	$	84,326		$	77,465
Less allowance for bad debts	(5,940		)	(5,839		)
	$	78,386		$	71,626

(Thousands of Dollars)	June 30, 2015		Dec. 31, 2014
Inventories
Materials and supplies	$	25,018	$	24,738
Fuel	7,437		18,493
	$	32,455	$	43,231

(Thousands of Dollars)	June 30, 2015			Dec. 31, 2014
Property, plant and equipment, net
Electric plant	$	5,580,225		$	5,376,606
Construction work in progress	291,565			238,519
Total property, plant and equipment	5,871,790			5,615,125
Less accumulated depreciation	(1,922,951		)	(1,871,984		)
	$	3,948,839		$	3,743,141

4. 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. The statute of limitations applicable to Xcel Energy’s 2009 federal income tax return expires in March 2016. In the third quarter of 2012, the Internal Revenue Service (IRS) commenced an examination of tax years 2010 and 2011, including a 2009 carryback claim. As of June 30, 2015, the IRS had proposed an adjustment to the federal tax loss carryback claims that would result in $12 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 June 30, 2015, the IRS has begun the appeals process; however, the outcome and timing of a resolution are uncertain.

State Audits — SPS is a member of the Xcel Energy affiliated group that files consolidated state income tax returns. As of June 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)	June 30, 2015		Dec. 31, 2014
Unrecognized tax benefit — Permanent tax positions	$	1.6	$	1.5
Unrecognized tax benefit — Temporary tax positions	12.6		11.7
Total unrecognized tax benefit	$	14.2	$	13.2

8

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)	June 30, 2015			Dec. 31, 2014
NOL and tax credit carryforwards	$	(6.0	)	$	(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 progresses and state audits resume. As the IRS examination moves closer to completion, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $2 million.

The payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryforwards. The payables for interest related to unrecognized tax benefits at June 30, 2015 and Dec. 31, 2014 were not material. No amounts were accrued for penalties related to unrecognized tax benefits as of June 30, 2015 or Dec. 31, 2014.

5. 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 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 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 May 2015, several intervenors filed direct testimony in response to SPS’ rate request, including the Alliance of Xcel Municipalities (AXM), the Office of Public Utility Counsel (OPUC), and the PUCT Staff (Staff).

• AXM recommended a rate decrease of $13.6 million, an ROE of 9.40 percent and an equity ratio of 53.97 percent.

• The OPUC recommended a rate increase of $1.8 million, an ROE of 9.20 percent and an equity ratio of 52.38 percent.

• The Staff recommended a rate decrease of $2.6 million, an ROE of 9.30 percent and an equity ratio of 53.97 percent.

In June 2015, SPS filed rebuttal testimony supporting a revised rate increase of approximately $42 million, or 4.4 percent.

										SPS Rebuttal Testimony
(Millions of Dollars)	AXM			OPUC			Staff
SPS’ revised rate request	$	58.9		$	58.9		$	58.9		$	58.9
Investment for capital expenditures — post-test year adjustments	(11.3		)	(23.8		)	(23.8		)	—
Lower ROE	(10.9		)	(13.5		)	(12.1		)	—
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		)
Depreciation expense	(13.3		)	—			—			—
Property taxes	—			(1.2		)	(4.4		)	(1.8		)
Revenue adjustments	(2.2		)	(0.2		)	—			—
Wholesale load reductions	(13.2		)	—			(11.1		)	—
Southwest Power Pool (SPP) transmission expansion plan	—			—			—			(7.3		)
Other, net	(1.7		)	(0.6		)	(2.2		)	(1.8		)
Total recommendation	$	(13.6	)	$	1.8		$	(2.6	)	$	46.4
Adjustment to move rate case expenses to a separate docket	—			—			—			(4.3		)
Recommendation, excluding rate case expenses	$	(13.6	)	$	1.8		$	(2.6	)	$	42.1

9

New rates will be made effective retroactive to June 11, 2015 as established by the PUCT. Hearings were completed in July 2015. A PUCT decision is expected in the fourth quarter of 2015.

Pending Regulatory Proceedings — New Mexico Public Regulation Commission (NMPRC)

New Mexico 2015 Electric Rate Case — In June 2015, SPS filed an electric rate case with the NMPRC for an increase in non-fuel base rates of $31.5 million and a base fuel decrease of $30.1 million. The rate filing was based on a 2016 forecast test year (FTY), a requested return on equity of 10.25 percent, a jurisdictional electric rate base of $777.9 million and an equity ratio of 53.97 percent.

In June 2015, SPS’ rate case application was dismissed by the NMPRC.  The NMPRC determined that the filing did not comply with its new interpretation of the statute regarding FTY periods and the corresponding timing of a rate case submission in relation to the FTY used in the case. This new interpretation occurred during the recent Public Service Company of New Mexico rate case.

In July, SPS filed an appeal with the New Mexico Supreme Court. In addition, SPS plans to file a rate case later this year.

Pending and Recently Concluded Regulatory Proceedings — Federal Energy Regulatory Commission (FERC)

Wholesale Rate ROE Complaints— In April 2012, Golden Spread Electric Cooperative, Inc. (Golden Spread), a wholesale cooperative customer, 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 base formula rate ROE of 10.77 percent, are unjust and unreasonable, and asking that the 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 ROE in the SPS production formula rate for Golden Spread and transmission formula rates be reduced to 9.15 and 9.65 percent, respectively, effective July 19, 2013. In June 2014, the FERC issued orders consolidating the Golden Spread ROE complaints and setting the complaints for settlement judge or hearing procedures.

A third rate complaint was filed in October 2014 by Golden Spread, certain New Mexico cooperatives and the West Texas Municipal Power Agency, requesting that the ROE in certain SPS production formula rates for Golden Spread and the New Mexico cooperatives and transmission formula rates be reduced, this time 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. The FERC established effective dates for refunds of April 20, 2012 (first refund period), July 19, 2013 (second refund period) and Oct. 20, 2014 (third refund period), respectively.

SPS sought rehearing of the FERC decisions to allow back-to-back complaints involving the same issue with consecutive 15 month refund periods, asserting this ruling is contrary to the governing statute. On May 12, 2015, FERC denied the rehearing request as it pertained to the first two rate complaints. In July 2015, SPS filed an appeal to the D.C. Circuit Court of Appeals of the FERC orders in the first two rate complaints allowing the sequential complaints and consecutive 15 month refund periods. The D.C. Circuit Court has not established a procedural schedule. FERC action on the similar SPS rehearing request related to the third complaint is pending.

In the first half of 2015, Golden Spread, SPS and FERC staff filed their initial testimonies recommending the following ROEs:

	Refund Period		Production ROE		Transmission ROE (a)
Golden Spread (b)	1		8.78	%	9.28	%
	2		8.51		9.01
	3		8.45		8.95
SPS	1		10.25		10.39
	2		10.25		11.20
	3	(c)	10.40		11.20
FERC Staff	1		8.97		9.47
	2		8.64		9.14
	3		8.53		9.03

^(a)  Includes a SPP RTO membership adder up to 50 basis points.

^(b)  For the third refund period, the recommended production and transmission ROEs are supported by Golden Spread, certain New Mexico cooperatives and the West Texas Municipal Power Agency (transmission ROE only).

^(c)  In addition to the recommended ROEs,SPS also filed testimony recommending the ROEs remain unchanged.

10

Hearings scheduled for July 2015 for the first two rate complaints were canceled and the parties agreed to file briefs based on pre-filed testimony. An initial ALJ decision on the first two complaints is expected to be issued by Nov. 25, 2015, and a final FERC order to be issued no earlier than 2016. A hearing for the third rate complaint is scheduled for Oct. 2015, with an ALJ initial decision expected in January 2016 and a final FERC order no earlier than later in 2016.

SPS recorded a current liability representing the current best estimate of a refund obligation associated with potential ROE adjustments as of June 30, 2015, and is reducing transmission and production revenues, net of expense, between $4 million and $6 million annually.

2004 FERC Complaint Case Orders—In August 2013, the FERC issued an order related to a 2004 complaint case brought by Golden Spread and Public Service Company of New Mexico (PNM) and an Order on Initial Decision in a subsequent 2006 production rate case filed by SPS.

The original complaint included two key components: 1) PNM’s claim regarding inappropriate allocation of fuel costs and 2) a base rate complaint, including the appropriate demand-related cost allocator. The FERC previously determined that the allocation of fuel costs and the demand-related cost allocator utilized by SPS was appropriate.

In the August 2013 Orders, the FERC clarified its previous ruling on the allocation of fuel costs and reaffirmed that the refunds in question should only apply to firm requirements customers and not PNM’s contractual load. The FERC also reversed its prior demand-related cost allocator decision. The FERC stated that it had erred in its initial analysis and concluded that the SPS system was a 3 coincident peak (CP) rather than a 12 CP system.

In September 2013, SPS filed a request for rehearing of the FERC ruling on the CP allocation and refund decisions. SPS asserted that the FERC applied an improper burden of proof and that precedent did not support retroactive refunds. PNM also requested rehearing of the FERC decision not to reverse its prior ruling. In October 2013, the FERC issued orders further considering the requests for rehearing, which are currently pending. As of Dec. 31, 2014, SPS had accrued $50.4 million related to the August 2013 Orders and an additional $1.5 million of principal and interest has been accrued during 2015.

2015 Production Formula Rate Change Filing—In January 2015, SPS filed to revise the production formula rates for six of its wholesale customers, including Golden Spread, certain New Mexico cooperatives and West Texas Municipal Power Agency, effective Feb. 1, 2015. The filing proposes several modifications, including a reduction in wholesale depreciation rates and the use of a 12 CP demand-related cost allocator for all wholesale customers. In March 2015, the FERC accepted this filing, effective July 1, 2015, subject to refund and settlement judge or hearing procedures. The parties remain engaged in settlement judge procedures. Effective June 1, 2015, the Golden Spread contract demand quantity subject to the formula rate change declined from 500 MW to 300 MW.

6. 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 in SPS’ Annual Report on Form 10-K for the year ended Dec. 31, 2014 and in Notes 5 and 6 to SPS’ Quarterly Report on Form 10-Q for the quarterly period ended March 31, 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 June 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.

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Environmental Contingencies

Environmental Requirements

Water

Federal Clean Water Act (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 will go into effect beginning in August 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.

Air

Cross-State Air Pollution Rule (CSAPR) — CSAPR addresses long range transport of particulate matter (PM) and ozone by requiring reductions in sulfur dioxide (SO₂) 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 United States District Court of Appeals for the District of Columbia Circuit (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 cost approximately $7 million or less.

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. On June 29, 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 SO₂, NOx and PM emissions under BART and set emissions limits for those facilities.

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Harrington Units 1 and 2 are potentially subject to BART. Texas developed a SIP that finds the CAIR equal to BART for electric generating units (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 currently plans to issue its final rule in December 2015.

In May 2014, the EPA issued a request for information under the CAA related to SO₂ 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 SO₂ 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 SO₂ — The EPA adopted a more stringent NAAQS for SO₂ 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 SO₂ emissions. The Texas Commission on Environmental Quality (TCEQ) is expected to make recommendations for nonattainment areas to the EPA in September 2015 with a decision by summer 2016. 

If an area is designated nonattainment, the respective states will need to evaluate all SO₂ 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 SO₂ 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 SO₂ 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.

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.

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7. 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 June 30, 2015			Twelve Months Ended Dec. 31, 2014
Borrowing limit	$	100		$	100
Amount outstanding at period end	—			16
Average amount outstanding	4			9
Maximum amount outstanding	36			100
Weighted average interest rate, computed on a daily basis	0.52		%	0.22		%
Weighted average interest rate at period end	N/A			0.45

Commercial Paper — SPS meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under its credit facility. Commercial paper outstanding for SPS was as follows:

(Amounts in Millions, Except Interest Rates)	Three Months Ended June 30, 2015			Twelve Months Ended Dec. 31, 2014
Borrowing limit	$	400		$	400
Amount outstanding at period end	209			37
Average amount outstanding	160			83
Maximum amount outstanding	209			241
Weighted average interest rate, computed on a daily basis	0.48		%	0.26		%
Weighted average interest rate at period end	0.49			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 June 30, 2015 and Dec. 31, 2014, there were $36.0 million and $30.0 million of letters of credit outstanding, respectively under the credit facility. The contract amounts of these letters of credit approximate their fair value and are subject to fees.

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

At June 30, 2015, SPS had the following committed credit facility available (in millions of dollars):

Credit Facility (a)		Drawn(b)		Available
$	400	$	245	$	155

^(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 June 30, 2015 and Dec. 31, 2014.

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8. 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 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.

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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 June 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 June 30, 2015 and Dec. 31, 2014:

(Amounts in Thousands) (a)	June 30, 2015	Dec. 31, 2014
Megawatt hours of electricity	13,620	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 each of the three and six months ended June 30, 2015 and 2014.

During the three and six months ended June 30, 2015, changes in the fair value of FTRs resulted in pre-tax net losses of $1.2 million and $2.0 million, respectively, recognized as regulatory assets and liabilities. For the three and six months ended June 30, 2014, changes in the fair value of FTRs resulted in pre-tax net losses of $1.0 million and $2.4 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 gains of $1.7 million and $1.6 million, respectively, were recognized for the three and six months ended June 30, 2015, respectively, recorded to electric fuel and purchased power. For the three and six months ended June 30, 2014, FTR settlement losses of $1.9 million and gains of $0.9 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 six months ended June 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.

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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 June 30, 2015, one of SPS’ eight most significant counterparties for these activities, comprising $9.6 million or 9 percent of this credit exposure, had investment grade credit ratings from Standard & Poor’s Ratings Services, Moody’s Investor Services or Fitch Ratings. Six of the eight most significant counterparties, comprising $58.5 million or 54 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 $1.3 million or 1 percent of this credit exposure, had credit quality less than investment grade, based on SPS’ internal analysis. All eight 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 June 30, 2015:

	June 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	$	—	$	—	$	21,533	$	21,533	$	(10,070	)	$	11,463
Total current derivative assets	$	—	$	—	$	21,533	$	21,533	$	(10,070	)	11,463
PPAs (a)												7,892
Current derivative instruments												$	19,355
Noncurrent derivative assets
PPAs (a)												$	29,218
Noncurrent derivative instruments												$	29,218
Current derivative liabilities
Other derivative instruments:
Electric commodity	$	—	$	—	$	10,070	$	10,070	$	(10,070	)	$	—
Total current derivative liabilities	$	—	$	—	$	10,070	$	10,070	$	(10,070	)	—
PPAs (a)												3,565
Current derivative instruments												$	3,565
Noncurrent derivative liabilities
PPAs (a)												$	28,860
Noncurrent derivative instruments												$	28,860

^(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 June 30, 2015. At June 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.

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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 six months ended June 30, 2015 and 2014:

	Three Months Ended June 30
(Thousands of Dollars)	2015			2014
Balance at April 1	$	6,457		$	5,791
Purchases	17,284			38,419
Settlements	(10,022		)	(13,554		)
Net transactions recorded during the period:
(Losses) Gains recognized as regulatory assets and liabilities	(2,256		)	3,286
Balance at June 30	$	11,463		$	33,942

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	Six Months Ended June 30
(Thousands of Dollars)	2015			2014
Balance at Jan. 1	$	15,884		$	9,933
Purchases	22,213			39,475
Settlements	(18,400		)	(14,655		)
Net transactions recorded during the period:
Losses recognized as regulatory assets and liabilities	(8,234		)	(811		)
Balance at June 30	$	11,463		$	33,942

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 six months ended June 30, 2015 and 2014.

Fair Value of Long-Term Debt

As of June 30, 2015 and Dec. 31, 2014, other financial instruments for which the carrying amount did not equal fair value were as follows:

	June 30, 2015				Dec. 31, 2014
(Thousands of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion	$	1,349,858	$	1,491,780	$	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 June 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.

9. Other Income (Expense), Net

Other income (expense), net consisted of the following:

	Three Months Ended June 30					Six Months Ended June 30
(Thousands of Dollars)	2015		2014			2015			2014
Interest income	$	13	$	53		$	45		$	240
Other nonoperating income	65		2			110			—
Insurance policy income (expense)	78		(184		)	(55		)	(328		)
Other income (expense), net	$	156	$	(129	)	$	100		$	(88	)

10. Benefit Plans and Other Postretirement Benefits

Components of Net Periodic Benefit Cost (Credit)

	Three Months Ended June 30
	2015			2014			2015			2014
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Service cost	$	2,751		$	2,296		$	238		$	311
Interest cost	5,046			5,111			437			643
Expected return on plan assets	(7,152		)	(6,545		)	(635		)	(811		)
Amortization of prior service cost (credit)	10			13			(100		)	(101		)
Amortization of net loss (gain)	3,772			3,331			(160		)	(81		)
Net periodic benefit cost (credit)	4,427			4,206			(220		)	(39		)
Credits recognized due to the effects of regulation	686			708			—			—
Net benefit cost (credit) recognized for financial reporting	$	5,113		$	4,914		$	(220	)	$	(39	)

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	Six Months Ended June 30
	2015			2014			2015			2014
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Service cost	$	5,503		$	4,592		$	477		$	623
Interest cost	10,092			10,222			873			1,286
Expected return on plan assets	(14,305		)	(13,090		)	(1,270		)	(1,623		)
Amortization of prior service cost (credit)	20			27			(200		)	(201		)
Amortization of net loss (gain)	7,544			6,663			(320		)	(161		)
Net periodic benefit cost (credit)	8,854			8,414			(440		)	(76		)
Credits recognized due to the effects of regulation	1,399			1,415			—			—
Net benefit cost (credit) recognized for financial reporting	$	10,253		$	9,829		$	(440	)	$	(76	)

In January 2015, contributions of $90.0 million were made across four of Xcel Energys pension plans, of which $11.6 million was attributable to SPS. Xcel Energy does not expect additional pension contributions during 2015.

11. Other Comprehensive Income

Changes in accumulated other comprehensive loss, net of tax, for the three and six months ended June 30, 2015 and 2014 were as follows:

	Gains and Losses on Cash Flow Hedges
(Thousands of Dollars)	Three Months Ended June 30, 2015			Three Months Ended June 30, 2014
Accumulated other comprehensive loss at April 1	$	(947	)	$	(1,118	)
Losses reclassified from net accumulated other comprehensive loss	43			42
Net current period other comprehensive income	43			42
Accumulated other comprehensive loss at June 30	$	(904	)	$	(1,076	)

	Gains and Losses on Cash Flow Hedges
(Thousands of Dollars)	Six Months Ended June 30, 2015			Six Months Ended June 30, 2014
Accumulated other comprehensive loss at Jan. 1	$	(989	)	$	(1,161	)
Losses reclassified from net accumulated other comprehensive loss	85			85
Net current period other comprehensive income	85			85
Accumulated other comprehensive loss at June 30	$	(904	)	$	(1,076	)

Reclassifications from accumulated other comprehensive loss for the three and six months ended June 30, 2015 and 2014 were as follows:

	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Three Months Ended June 30, 2015				Three Months Ended June 30, 2014
Losses on cash flow hedges:
Interest rate derivatives	$	67		(a)	$	66		(a)
Total, pre-tax	67				66
Tax benefit	(24		)		(24		)
Total amounts reclassified, net of tax	$	43			$	42

20

	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Six Months Ended June 30, 2015				Six Months Ended June 30, 2014
Losses on cash flow hedges:
Interest rate derivatives	$	133		(a)	$	133		(a)
Total, pre-tax	133				133
Tax benefit	(48		)		(48		)
Total amounts reclassified, net of tax	$	85			$	85

^(a)  Included in interest charges.

Item 2 — MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Discussion of financial condition and liquidity for SPS is omitted per conditions set forth in general instructions H (1) (a) and (b) of Form 10-Q for wholly owned subsidiaries. It is replaced with management’s narrative analysis of the results of operations set forth in general instructions H (2) (a) of Form 10-Q for wholly owned subsidiaries (reduced disclosure format).

Financial Review

The following discussion and analysis by management focuses on those factors that had a material effect on SPS’ financial condition, results of operations, and cash flows during the periods presented, or are expected to have a material impact in the future. It should be read in conjunction with the accompanying unaudited financial statements and the related notes to the financial statements.  Due to the seasonality of SPS’ electric sales, such interim results are not necessarily an appropriate base from which to project annual results.

Forward-Looking Statements

Except for the historical statements contained in this report, the matters discussed in the following discussion and analysis are forward-looking statements that are subject to certain risks, uncertainties and assumptions.  Such forward-looking statements are intended to be identified in this document by the words “anticipate,” “believe,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should” and similar expressions.  Actual results may vary materially.  Forward-looking statements speak only as of the date they are made, and we do not undertake any obligation to update them to reflect changes that occur after that date.  Factors that could cause actual results to differ materially include, but are not limited to: general economic conditions, including inflation rates, monetary fluctuations and their impact on capital expenditures and the ability of SPS to obtain financing on favorable terms; business conditions in the energy industry, including the risk of a slowdown in the U.S. economy or delay in growth recovery; trade, fiscal, taxation and environmental policies in areas where SPS has a financial interest; customer business conditions; actions of credit rating agencies; competitive factors, including the extent and timing of the entry of additional competition in the markets served by SPS; unusual weather; effects of geopolitical events, including war and acts of terrorism; cyber security threats and data security breaches; state, federal and foreign legislative and regulatory initiatives that affect cost and investment recovery, have an impact on rates or have an impact on asset operation or ownership or impose environmental compliance conditions; structures that affect the speed and degree to which competition enters the electric market; costs and other effects of legal and administrative proceedings, settlements, investigations and claims; financial or regulatory accounting policies imposed by regulatory bodies; availability or cost of capital; employee work force factors; and the other risk factors listed from time to time by SPS in reports filed with the SEC, including Risk Factors in Item 1A of SPS’ Form 10-K for the year ended Dec. 31, 2014, and Item 1A and Exhibit 99.01 to this Quarterly Report on Form 10-Q for the quarter ended June 30, 2015.

21

Results of Operations

SPS’ net income was approximately $42.8 million for the six months endedJune 30, 2015, compared with net income of approximately $46.8 million for the same period in 2014. Higher electric rates in Texas were offset by higher operating and maintenance (O&M) expenses, depreciation, and lower AFUDC, along with the impact of unfavorable weather.

Electric Revenues and Margin

Electric fuel and purchased power expenses tend to vary with changing retail and wholesale sales requirements and unit cost changes in fuel and purchased power. The design of fuel and purchased power cost recovery mechanisms of the Texas and New Mexico jurisdictions may not allow for complete recovery of all expenses and, therefore, changes in fuel or purchased power costs can impact earnings. The following tables detail the electric revenues and margin:

	Six Months Ended June 30
(Millions of Dollars)	2015			2014
Electric revenues	$	847		$	941
Electric fuel and purchased power	(489		)	(603		)
Electric margin	$	358		$	338

The following tables summarize the components of the changes in electric revenues and electric margin for the six months ended June 30:

Electric Revenues

(Millions of Dollars)	2015 vs. 2014
Fuel and purchased power cost recovery	$	(149	)
Estimated impact of weather	(7		)
Trading	25
Retail rate increases (Texas)	19
Transmission revenue	15
Other, net	3
Total decrease in electric revenues	$	(94	)

Electric Margin

(Millions of Dollars)	2015 vs. 2014
Retail rate increases (Texas)	$	19
Transmission revenue, net of costs	8
Fuel recovery	3
Estimated impact of weather	(7		)
Fuel handling and procurement	(4		)
Other, net	1
Total increase in electric margin	$	20

Non-Fuel Operating Expense and Other Items

O&M Expenses — O&M expenses increased $9.4 million, or 6.8 percent, for the six months ended June 30, 2015 compared with the same period in 2014. The following table summarizes the changes in O&M expenses:

(Millions of Dollars)	2015 vs. 2014
Employee benefits	$	3
Plant generation costs	2
Distribution cost increases	1
Other, net	3
Total increase in O&M expenses	$	9

22

Depreciation and Amortization — Depreciation and amortization increased $6.9 million, or 10.5 percent, for the six months ended June 30, 2015 compared with the same period in 2014. The increase is primarily due to normal system expansion.

Taxes (Other Than Income Taxes) — Taxes (other than income taxes) increased $2.3 million, or 8.8 percent, for the six months ended June 30, 2015 compared with the same period in 2014. The increase is primarily due to an increase in property taxes.

Allowance for Funds Used During Construction (AFUDC) —AFUDC decreased $4.7 million for the six months ended June 30, 2015 compared with the same period in 2014. The decrease is primarily due to the decrease of transmission facilities construction.

Interest Charges — Interest charges increased $3.0 million, or 7.8 percent, for the six months ended June 30, 2015 compared with the same period in 2014. The increase is primarily due to higher long-term debt levels, partially offset by lower interest rates.

Income Taxes — Income tax expense decreased $2.3 million for the six months ended June 30, 2015 compared with the same period in 2014. The decrease in income tax expense is primarily due to lower pre-tax earnings, partially offset by decreased permanent plant-related adjustments in 2015. The ETR was 35.8 percent for the six months ended June 30, 2015, compared with 35.9 percent for the same period in 2014.

Public Utility Regulation

Except to the extent noted below, the circumstances set forth in Public Utility Regulation included in Item 1. of SPS' Annual Report on Form 10-K for the year ended Dec. 31, 2014, and Public Utility Regulation included in Item 2. of SPS' Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2015, appropriately represent, in all material respects, the current status of public utility regulation, and are incorporated herein by reference.

Texas Legislation — In June 2015, the Texas Governor signed HB 1535 into law. As a result, SPS may reduce regulatory lag through earlier inclusion of certain capital additions in rate base as well as expediting the implementation of new rates. Key provisions of the bill are as follows:

• Utilities may include actual and estimated post-test year capital additions up through 30-days before the filing date;

• A new natural gas generating unit may be included in rate base as long as it is in service before the proposed effective rate date;

• Rates will go into effect 155 days after filing (previously it was 185 days). If the case is not final by this date, then a utility can go back and surcharge; and 

• Establishes time limits for the PUCT to rule on a new generation plant request for a certificate of convenience and necessity.

Summary of Recent Federal Regulatory Developments

The FERC has jurisdiction over rates for electric transmission service in interstate commerce and electricity sold at wholesale, asset transactions and mergers, accounting practices and certain other activities of SPS, including enforcement of North American Electric Reliability Corporation mandatory electric reliability standards. State and local agencies have jurisdiction over many of SPS’ activities, including regulation of retail rates and environmental matters. See additional discussion in the summary of recent federal regulatory developments and public utility regulation sections of the SPS Annual Report on Form 10-K for the year ended Dec. 31, 2014. In addition to the matters discussed below, see Note 5 to the financial statements for a discussion of other regulatory matters.

FERC Order, New ROE Policy — In June 2014, the FERC adopted a new two-step ROE methodology for electric utilities. The issue of how to apply the new FERC ROE methodology is being contested in various complaint proceedings. FERC is not expected to issue orders in any of the ROE complaint proceedings until 2016. See Note 5 to the consolidated financial statements for discussion of the Wholesale Rate complaints.

Item 4 — CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

SPS maintains a set of disclosure controls and procedures designed to ensure that information required to be disclosed in the reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized, and reported within the time periods specified in SEC rules and forms.  In addition, the disclosure controls and procedures ensure that information required to be disclosed is accumulated and communicated to management, including the chief executive officer (CEO) and chief financial officer (CFO), allowing timely decisions regarding required disclosure.  As of June 30, 2015, based on an evaluation carried out under the supervision and with the participation of SPS’ management, including the CEO and CFO, of the effectiveness of its disclosure controls and the procedures, the CEO and CFO have concluded that SPS’ disclosure controls and procedures were effective.

Internal Control Over Financial Reporting

No change in SPS’ internal control over financial reporting has occurred during SPS’ most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, SPS’ internal control over financial reporting.

Part II — OTHER INFORMATION

Item 1 — LEGAL PROCEEDINGS

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.

Additional Information

See Note 6 to the financial statements for further discussion of legal claims and environmental proceedings.  See Note 5 to the financial statements for discussion of proceedings involving utility rates and other regulatory matters.

Item 1A — RISK FACTORS

SPS’ risk factors are documented in Item 1A of Part I of its Annual Report on Form 10-K for the year ended Dec. 31, 2014, which is incorporated herein by reference. There have been no material changes from the risk factors previously disclosed in the Form 10-K.

Item 4—MINE SAFETY DISCLOSURES

None.

Item 5—OTHER INFORMATION

None.

23

Item 6 — EXHIBITS

*  Indicates incorporation by reference

3.01*	Amended and Restated Articles of Incorporation of SPS dated Sept. 30, 1997 (Exhibit 3(a)(2) to Form 10-K (file no. 001-03789) dated March 3, 1998).
3.02*	By-Laws of SPS as Amended and Restated on Sept. 26, 2013. (Exhibit 3.02 to Form 10-Q/A for the quarter ended Sept. 30, 2013 (file no. 001-03789)).
31.01	Principal Executive Officer’s certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.02	Principal Financial Officer’s certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.01	Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.01	Statement pursuant to Private Securities Litigation Reform Act of 1995.
101	The following materials from SPS’ Quarterly Report on Form 10-Q for the quarter ended June 30, 2015 are formatted in XBRL (eXtensible Business Reporting Language):  (i) the Statements of Income, (ii) the Statements of Comprehensive Income (iii) the Statements of Cash Flows, (iv) the Balance Sheets, (v) Notes to Financial Statements, and (vi) document and entity information.

24

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

		Southwestern Public Service Company
Aug. 3, 2015	By:	/s/ JEFFREY S. SAVAGE
		Jeffrey S. Savage
		Senior Vice President, Controller
		(Principal Accounting Officer)
		/s/ TERESA S. MADDEN
		Teresa S. Madden
		Executive Vice President, Chief Financial Officer and Director
		(Principal Financial Officer)

25

EX-31.01

Exhibit 31.01

CERTIFICATION

I, Ben Fowke, certify that:

1. I have reviewed this report on Form 10-Q of Southwestern Public Service Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: Aug. 3, 2015

/s/ BEN FOWKE

Ben Fowke

Chairman, Chief Executive Officer and Director

(Principal Executive Officer)

1

EX-31.02

Exhibit 31.02

CERTIFICATION

I, Teresa S. Madden, certify that:

1. I have reviewed this report on Form 10-Q of Southwestern Public Service Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting

Date: Aug. 3, 2015

/s/ TERESA S. MADDEN

Teresa S. Madden

Executive Vice President, Chief Financial Officer and Director

(Principal Financial Officer)

2

EX-32.01

Exhibit 32.01

OFFICER CERTIFICATION

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Southwestern Public Service Company (SPS) on Form 10-Q for the quarter ended June 30, 2015, as filed with the SEC on the date hereof (Form 10-Q), each of the undersigned officers of SPS certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to such officer’s knowledge:

(1) The Form 10-Q fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of SPS as of the dates and for the periods expressed in the Form 10-Q.

Date: Aug. 3, 2015

/s/ BEN FOWKE

Ben Fowke

Chairman, Chief Executive Officer and Director

(Principal Executive Officer)

/s/ TERESA S. MADDEN

Teresa S. Madden

Executive Vice President, Chief Financial Officer and Director

(Principal Financial Officer)

The foregoing certification is being furnished solely pursuant to 18 U.S.C. Section 1350 and is not being filed as part of the Report or as a separate disclosure document.

A signed original of this written statement required by Section 906, or other document authenticating, acknowledging or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to SPS and will be retained by SPS and furnished to the SEC or its staff upon request.

1

EX-99.01

Exhibit 99.01

SPS Cautionary Factors

The Private Securities Litigation Reform Act provides a “safe harbor” for forward-looking statements to encourage such disclosures without the threat of litigation, providing those statements are identified as forward-looking and are accompanied by meaningful, cautionary statements identifying important factors that could cause the actual results to differ materially from those projected in the statement.  Forward-looking statements are made in written documents and oral presentations of SPS, Xcel Energy Inc. or any of its other subsidiaries.  These statements are based on management’s beliefs as well as assumptions and information currently available to management.  Such forward-looking statements are intended to be identified in this document by the words “anticipate,” “believe,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should” and similar expressions.  In addition to any assumptions and other factors referred to specifically in connection with such forward-looking statements, factors that could cause SPS’ actual results to differ materially from those contemplated in any forward-looking statements include, among others, the following:

• Economic conditions, including inflation rates, monetary fluctuations and their impact on capital expenditures;

• The risk of a significant slowdown in growth or decline in the U.S. economy, the risk of delay in growth recovery in the U.S. economy or the risk of increased cost for insurance premiums, security and other items as a consequence of past or future terrorist attacks;

• Trade, monetary, fiscal, taxation and environmental policies of governments, agencies and similar organizations in geographic areas where SPS has a financial interest;

• Customer business conditions, including demand for their products or services and supply of labor and materials used in creating their products and services;

• Financial or regulatory accounting principles or policies imposed by the FASB, the SEC, the FERC and similar entities with regulatory oversight;

• Availability or cost of capital such as changes in: interest rates; market perceptions of the utility industry, SPS, Xcel Energy Inc. or any of its other subsidiaries; or security ratings;

• Factors affecting utility operations such as unusual weather conditions; catastrophic weather-related damage; unscheduled generation outages, maintenance or repairs; unanticipated changes to fossil fuel or natural gas supply costs or availability due to higher demand, shortages, transportation problems or other developments; environmental incidents; cyber incidents; or electric transmission or natural gas pipeline constraints;

• Employee workforce factors, including loss or retirement of key executives, collective-bargaining agreements with union employees, or work stoppages;

• Increased competition in the utility industry or additional competition in the markets served by SPS, Xcel Energy Inc. and its other subsidiaries;

• State and federal legislative and regulatory initiatives that affect cost and investment recovery, have an impact on rate structures and affect the speed and degree to which competition enters the electric market; industry restructuring initiatives; transmission system operation and/or administration initiatives; recovery of investments made under traditional regulation; nature of competitors entering the industry; retail wheeling; a new pricing structure; and former customers entering the generation market;

• Environmental laws and regulations, including legislation and regulations relating to climate change, and the associated cost of compliance;

• Rate-setting policies or procedures of regulatory entities, including environmental externalities, which are values established by regulators assigning environmental costs to each method of electricity generation when evaluating generation resource options;

• Social attitudes regarding the utility and power industries;

• Cost and other effects of legal and administrative proceedings, settlements, investigations and claims;

• Technological developments that result in competitive disadvantages and create the potential for impairment of existing assets;

• Risks associated with implementation of new technologies; and

• Other business or investment considerations that may be disclosed from time to time in SEC filings, including “Risk Factors” in Item 1A of SPS’ Form 10-K for the year ended Dec. 31, 2014, or in other publicly disseminated written documents.

 SPS undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.  The foregoing review of factors should not be construed as exhaustive.

1

XML

Fair Value of Financial Assets and Liabilities, Derivative Instruments (Details) MWh in Thousands, $ in Millions		Jun. 30, 2015 USD ($) MWh Counterparty	Dec. 31, 2014 MWh
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		8
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		$ 9.6
Percentage of wholesale, trading and non-trading commodity credit exposure for the most significant counterparties (in hundredths)		9.00%
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		6
Wholesale, trading and non-trading commodity credit exposure for the most significant counterparties		$ 58.5
Percentage of wholesale, trading and non-trading commodity credit exposure for the most significant counterparties (in hundredths)		54.00%
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		$ 1.3
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]	13,620	6,930

[1] (a) Amounts are not reflective of net positions in the underlying commodities.

XML

Rate Matters (Details) $ in Thousands					1 Months Ended										3 Months Ended	6 Months Ended
		Jun. 08, 2015 USD ($)	Jun. 01, 2015 MW	May. 12, 2015	Jul. 31, 2015	Jun. 30, 2015 USD ($)	May. 31, 2015 USD ($)	Mar. 31, 2015 USD ($)	Jan. 31, 2015	Dec. 31, 2014 USD ($)	Oct. 31, 2014	Aug. 31, 2013 Factor	Jul. 31, 2013	Apr. 30, 2012	Jun. 30, 2015 USD ($)	Jun. 30, 2015 USD ($)
Public Utilities, General Disclosures [Line Items]
Other Liabilities, Current						$ 90,838				$ 80,211					$ 90,838	$ 90,838
Texas 2015 Electric Rate Case
Public Utilities, General Disclosures [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount										$ 64,800
Public Utilities, Requested Rate Increase (Decrease), Percentage										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 (decrease)								$ 58,900
Public Utilities, Additional capital investment										$ 392,000
FERC Proceeding - FERC Orders
Public Utilities, General Disclosures [Line Items]
Number of components included in regulatory proceeding | Factor												2
Other Liabilities, Current										$ 50,400
Current year increase (decrease) to pre-tax earnings resulting from regulatory proceedings																$ 1,500
Number of customers for which a public utility proposes to revise formula rates									6
Federal Energy Regulatory Commission (FERC) | FERC Proceeding - FERC Orders
Public Utilities, General Disclosures [Line Items]
Number of coincident peaks used as demand allocator, revised												3
Number of coincident peaks used as demand allocator, original												12
SPS | Wholesale Electric Rate Complaint, April 20, 2012 through July 18, 2013 Impact
Public Utilities, General Disclosures [Line Items]
Public Utilities, First refund period															1
Public Utilities, Base return on equity requested charged to customers through production formula rates, Percentage															10.25%
Public Utilities, Base return on equity requested charged to customers through transmission formula rates, Percentage	[1]														10.39%
SPS | Wholesale Electric Rate Complaints
Public Utilities, General Disclosures [Line Items]
Public Utilities, Base return on equity charged to customers through production formula rates, Percentage														10.25%
Public Utilities, Base return on equity charged to customers through transmission formula rates, Percentage														10.77%
Public Utilities, Base return on equity requested 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%
Public Utilities, Incremental ROE basis point increase (decrease) recommended by third parties															50
SPS | Wholesale Electric Rate Complaints, Refunds as of April 20, 2012 and July 19, 2013
Public Utilities, General Disclosures [Line Items]
FERC denied the rehearing request as it pertained to the first two rate complaints				2
Public Utilities, rehearing sought in FERC decision regarding number of consecutive month periods															15 months
Number of hearings scheduled that were canceled and parties agreed to file briefs based on pre-filed testimony																2
Number of complaints where decision is expected by ALJ in the future																2
SPS | Texas 2015 Electric Rate Case
Public Utilities, General Disclosures [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount						$ 42,000
Public Utilities, Requested Rate Increase (Decrease), Percentage						4.40%
Public Utilities, Revised requested rate increase (decrease)								58,900
Public Utilities, Rate increase (decrease) recommended by rebuttal testimony						$ 46,400
Public Utilities, Post test year adjustment related to capital expenditures						0
Public Utilities, ROE						0
Rate base adjustments (largely the removal of the prepaid pension asset)						0
Public Utilities, Operating and maintenance expenses						(1,600)
Public Utilities, Depreciation expense						0
Public Utilities, Property taxes						(1,800)
Public Utilities, Revenue adjustments						0
Public Utilities, Wholesale load reductions						0
Public Utilities, SPP transmission expansion plan						(7,300)
Public Utilities, Other net						(1,800)
Public Utilities, Adjustment to move rate case expenses to separate docket						(4,300)
Public Utilities, Rate increase (decrease) recommended by rebuttal testimony, excluding rate case expenses						$ 42,100
SPS | New Mexico 2014 Electric Rate Case
Public Utilities, General Disclosures [Line Items]
Public Utilities, Requested Return on Equity, Percentage		10.25%
Public Utilities, Jurisdictional electric rate base		$ 777,900
Public Utilities, Requested Equity Capital Structure, Percentage		53.97%
Public Utilities, Non-fuel proposed base rate increase (decrease)		$ 31,500
Public Utilities, Proposed base fuel rate increase (decrease)		$ (30,100)
SPS | FERC Proceeding - FERC Orders
Public Utilities, General Disclosures [Line Items]
Number of coincident peaks used as demand allocator, original									12
Golden Spread contract demand quantity subject to the formula rate change prior to June 1, 2015 | MW			500
Change in Golden Spread contract demand quantity subject to the formula rate change | MW			300
SPS | Wholesale Electric Rate Complaint, July 19, 2013 through Oct. 19, 2014 Impact
Public Utilities, General Disclosures [Line Items]
Public Utilities, Base return on equity requested charged to customers through production formula rates, Percentage															10.25%
Public Utilities, Base return on equity requested charged to customers through transmission formula rates, Percentage	[1]														11.20%
Public Utilities, Second refund period															2
SPS | Wholesale Electric Rate Complaint, Oct. 20, 2014 Impact
Public Utilities, General Disclosures [Line Items]
Public Utilities, Base return on equity requested charged to customers through production formula rates, Percentage	[2]														10.40%
Public Utilities, Base return on equity requested charged to customers through transmission formula rates, Percentage	[1],[2]														11.20%
Public Utilities, Third refund period															3
SPS | Golden Spread [Member] | Wholesale Electric Rate Complaint, April 20, 2012 through July 18, 2013 Impact
Public Utilities, General Disclosures [Line Items]
Public Utilities, First refund period	[3]														1
Public Utilities, Base return on equity requested by customers to be charged through production formula rates, Percentage	[3]														8.78%
Public Utilities, Base return on equity requested by customers to be charged through transmission formula rates, Percentage	[1],[3]														9.28%
SPS | Golden Spread [Member] | Wholesale Electric Rate Complaint, July 19, 2013 through Oct. 19, 2014 Impact
Public Utilities, General Disclosures [Line Items]
Public Utilities, Base return on equity requested by customers to be charged through production formula rates, Percentage	[3]														8.51%
Public Utilities, Base return on equity requested by customers to be charged through transmission formula rates, Percentage	[1],[3]														9.01%
Public Utilities, Second refund period	[3]														2
SPS | Golden Spread [Member] | Wholesale Electric Rate Complaint, Oct. 20, 2014 Impact
Public Utilities, General Disclosures [Line Items]
Public Utilities, Base return on equity requested by customers to be charged through production formula rates, Percentage	[3]														8.45%
Public Utilities, Base return on equity requested by customers to be charged through transmission formula rates, Percentage	[1],[3]														8.95%
Public Utilities, Third refund period	[3]														3
SPS | Alliance of Xcel Municipalities [Member] | Texas 2015 Electric Rate Case
Public Utilities, General Disclosures [Line Items]
Public Utilities, Revised requested rate increase (decrease)								58,900
Public Utilities, Rate increase (decrease) recommended by third parties							$ (13,600)
Public utilities, ROE recommended by third parties							9.40%
Public Utilities, Equity capital structure recommended by third parties							53.97%
Public Utilities, Post test year adjustment related to capital expenditures							$ (11,300)
Public Utilities, ROE							(10,900)
Rate base adjustments (largely the removal of the prepaid pension asset)							(6,200)
Public Utilities, Operating and maintenance expenses							(13,700)
Public Utilities, Depreciation expense							(13,300)
Public Utilities, Property taxes							0
Public Utilities, Revenue adjustments							(2,200)
Public Utilities, Wholesale load reductions							(13,200)
Public Utilities, SPP transmission expansion plan							0
Public Utilities, Other net							(1,700)
Public Utilities, Adjustment to move rate case expenses to separate docket							0
Public Utilities, Rate increase (decrease) recommended by third parties excluding rate case expenses							(13,600)
SPS | Office of Public Utility Counsel [Member] | Texas 2015 Electric Rate Case
Public Utilities, General Disclosures [Line Items]
Public Utilities, Revised requested rate increase (decrease)								58,900
Public Utilities, Rate increase (decrease) recommended by third parties							$ 1,800
Public utilities, ROE recommended by third parties							9.20%
Public Utilities, Equity capital structure recommended by third parties							52.38%
Public Utilities, Post test year adjustment related to capital expenditures							$ (23,800)
Public Utilities, ROE							(13,500)
Rate base adjustments (largely the removal of the prepaid pension asset)							(6,800)
Public Utilities, Operating and maintenance expenses							(11,000)
Public Utilities, Depreciation expense							0
Public Utilities, Property taxes							(1,200)
Public Utilities, Revenue adjustments							(200)
Public Utilities, Wholesale load reductions							0
Public Utilities, SPP transmission expansion plan							0
Public Utilities, Other net							(600)
Public Utilities, Adjustment to move rate case expenses to separate docket							0
Public Utilities, Rate increase (decrease) recommended by third parties excluding rate case expenses							1,800
SPS | Public Utility Commission of Texas Staff [Member] | Texas 2015 Electric Rate Case
Public Utilities, General Disclosures [Line Items]
Public Utilities, Revised requested rate increase (decrease)								$ 58,900
Public Utilities, Rate increase (decrease) recommended by third parties							$ (2,600)
Public utilities, ROE recommended by third parties							9.30%
Public Utilities, Equity capital structure recommended by third parties							53.97%
Public Utilities, Post test year adjustment related to capital expenditures							$ (23,800)
Public Utilities, ROE							(12,100)
Rate base adjustments (largely the removal of the prepaid pension asset)							0
Public Utilities, Operating and maintenance expenses							(7,900)
Public Utilities, Depreciation expense							0
Public Utilities, Property taxes							(4,400)
Public Utilities, Revenue adjustments							0
Public Utilities, Wholesale load reductions							(11,100)
Public Utilities, SPP transmission expansion plan							0
Public Utilities, Other net							(2,200)
Public Utilities, Adjustment to move rate case expenses to separate docket							0
Public Utilities, Rate increase (decrease) recommended by third parties excluding rate case expenses							$ (2,600)
SPS | FERC Staff [Member] | Wholesale Electric Rate Complaint, April 20, 2012 through July 18, 2013 Impact
Public Utilities, General Disclosures [Line Items]
Public Utilities, First refund period															1
Public Utilities, Base return on equity requested by the FERC through production formula rates, Percentage															8.97%
Public Utilities, Base return on equity requested by the FERC through transmission formula rates, Percentage	[1]														9.47%
SPS | FERC Staff [Member] | Wholesale Electric Rate Complaint, July 19, 2013 through Oct. 19, 2014 Impact
Public Utilities, General Disclosures [Line Items]
Public Utilities, Base return on equity requested by the FERC through production formula rates, Percentage															8.64%
Public Utilities, Base return on equity requested by the FERC through transmission formula rates, Percentage	[1]														9.14%
Public Utilities, Second refund period															2
SPS | FERC Staff [Member] | Wholesale Electric Rate Complaint, Oct. 20, 2014 Impact
Public Utilities, General Disclosures [Line Items]
Public Utilities, Base return on equity requested by the FERC through production formula rates, Percentage															8.53%
Public Utilities, Base return on equity requested by the FERC through transmission formula rates, Percentage	[1]														9.03%
Public Utilities, Third refund period															3
Minimum | SPS | Wholesale Electric Rate Complaints
Public Utilities, General Disclosures [Line Items]
Public Utilities, Increase (Decrease) of transmission and production revenues, net of expense due to potential ROE adjustments																$ (4,000)
Maximum | SPS | Wholesale Electric Rate Complaints
Public Utilities, General Disclosures [Line Items]
Public Utilities, Increase (Decrease) of transmission and production revenues, net of expense due to potential ROE adjustments																$ (6,000)
Subsequent Event | SPS | Wholesale Electric Rate Complaints, Refunds as of April 20, 2012 and July 19, 2013
Public Utilities, General Disclosures [Line Items]
Public Utilities, Number of rate complaints where appeal was filed with the D.C. Circuit Court of Appeals due to the FERC orders to allow back-to-back complaints for consecutive month refund periods					2
Public Utilities, appeal of the number of months refund period					15 months

[1] Includes a SPP RTO membership adder up to 50 basis points.

[2] In addition to the recommended ROEs, SPS also filed testimony recommending the ROEs remain unchanged.

[3] For the third refund period, the recommended production and transmission ROEs are supported by Golden Spread, certain New Mexico cooperatives and the West Texas Municipal Power Agency (transmission ROE only).

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Fair Value of Financial Assets and Liabilities (Tables)

6 Months Ended

Jun. 30, 2015

Fair Value Disclosures [Abstract]

Gross Notional Amounts of Commodity FTRs

The following table details the gross notional amounts of commodity FTRs at June 30, 2015 and Dec. 31, 2014:

(Amounts in Thousands) (a)	June 30, 2015	Dec. 31, 2014
Megawatt hours of electricity	13,620	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 June 30, 2015:

	June 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	$	—	$	—	$	21,533	$	21,533	$	(10,070	)	$	11,463
Total current derivative assets	$	—	$	—	$	21,533	$	21,533	$	(10,070	)	11,463
PPAs (a)												7,892
Current derivative instruments												$	19,355
Noncurrent derivative assets
PPAs (a)												$	29,218
Noncurrent derivative instruments												$	29,218
Current derivative liabilities
Other derivative instruments:
Electric commodity	$	—	$	—	$	10,070	$	10,070	$	(10,070	)	$	—
Total current derivative liabilities	$	—	$	—	$	10,070	$	10,070	$	(10,070	)	—
PPAs (a)												3,565
Current derivative instruments												$	3,565
Noncurrent derivative liabilities
PPAs (a)												$	28,860
Noncurrent derivative instruments												$	28,860

^(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 June 30, 2015. At June 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 six months ended June 30, 2015 and 2014:

	Three Months Ended June 30
(Thousands of Dollars)	2015			2014
Balance at April 1	$	6,457		$	5,791
Purchases	17,284			38,419
Settlements	(10,022		)	(13,554		)
Net transactions recorded during the period:
(Losses) Gains recognized as regulatory assets and liabilities	(2,256		)	3,286
Balance at June 30	$	11,463		$	33,942

	Six Months Ended June 30
(Thousands of Dollars)	2015			2014
Balance at Jan. 1	$	15,884		$	9,933
Purchases	22,213			39,475
Settlements	(18,400		)	(14,655		)
Net transactions recorded during the period:
Losses recognized as regulatory assets and liabilities	(8,234		)	(811		)
Balance at June 30	$	11,463		$	33,942

Carrying Amount and Fair Value of Long-term Debt

As of June 30, 2015 and Dec. 31, 2014, other financial instruments for which the carrying amount did not equal fair value were as follows:

	June 30, 2015				Dec. 31, 2014
(Thousands of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion	$	1,349,858	$	1,491,780	$	1,349,691	$	1,572,414

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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		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Balance at beginning of period	$ 6,457,000	$ 5,791,000	$ 15,884,000	$ 9,933,000
Purchases	17,284,000	38,419,000	22,213,000	39,475,000
Settlements	(10,022,000)	(13,554,000)	(18,400,000)	(14,655,000)
Losses recognized as regulatory assets and liabilities	(2,256,000)	3,286,000	(8,234,000)	(811,000)
Balance at end of period	11,463,000	33,942,000	11,463,000	33,942,000
Transfers into Level 3	0	0	0	0
Transfers out of Level 3	$ 0	$ 0	$ 0	$ 0

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Borrowings and Other Financing Instruments, Letters of Credit (Details) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2015	Dec. 31, 2014
Line of Credit Facility [Line Items]
Amount outstanding at period end	$ 209,000	$ 37,000
Letter of Credit
Line of Credit Facility [Line Items]
Amount outstanding at period end	$ 36,000	$ 30,000
Letter of Credit | Letter of Credit
Line of Credit Facility [Line Items]
Term of letters of credit (in years)	1 year

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Management's Opinion

6 Months Ended

Jun. 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 June 30, 2015, and Dec. 31, 2014; the results of its operations, including the components of net income and comprehensive income, for the three and six months ended June 30, 2015 and 2014; and its cash flows for the six months endedJune 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 June 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.

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Fair Value of Financial Assets and Liabilities, Fair Value of Long-Term Debt (Details) - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014
Carrying Amount
Financial Liabilities, Balance Sheet Groupings [Abstract]
Long-term debt, including current portion	$ 1,349,858	$ 1,349,691
Fair Value
Financial Liabilities, Balance Sheet Groupings [Abstract]
Long-term debt, including current portion	$ 1,491,780	$ 1,572,414

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Selected Balance Sheet Data (Details) - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014
Accounts receivable, net
Accounts receivable	$ 84,326	$ 77,465
Less allowance for bad debts	(5,940)	(5,839)
Accounts receivable, net	$ 78,386	$ 71,626

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Other Comprehensive Income (Tables)

6 Months Ended

Jun. 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 six months ended June 30, 2015 and 2014 were as follows:

	Gains and Losses on Cash Flow Hedges
(Thousands of Dollars)	Three Months Ended June 30, 2015			Three Months Ended June 30, 2014
Accumulated other comprehensive loss at April 1	$	(947	)	$	(1,118	)
Losses reclassified from net accumulated other comprehensive loss	43			42
Net current period other comprehensive income	43			42
Accumulated other comprehensive loss at June 30	$	(904	)	$	(1,076	)

	Gains and Losses on Cash Flow Hedges
(Thousands of Dollars)	Six Months Ended June 30, 2015			Six Months Ended June 30, 2014
Accumulated other comprehensive loss at Jan. 1	$	(989	)	$	(1,161	)
Losses reclassified from net accumulated other comprehensive loss	85			85
Net current period other comprehensive income	85			85
Accumulated other comprehensive loss at June 30	$	(904	)	$	(1,076	)

Reclassifications out of Accumulated Other Comprehensive Loss

Reclassifications from accumulated other comprehensive loss for the three and six months ended June 30, 2015 and 2014 were as follows:

	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Three Months Ended June 30, 2015				Three Months Ended June 30, 2014
Losses on cash flow hedges:
Interest rate derivatives	$	67		(a)	$	66		(a)
Total, pre-tax	67				66
Tax benefit	(24		)		(24		)
Total amounts reclassified, net of tax	$	43			$	42

	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Six Months Ended June 30, 2015				Six Months Ended June 30, 2014
Losses on cash flow hedges:
Interest rate derivatives	$	133		(a)	$	133		(a)
Total, pre-tax	133				133
Tax benefit	(48		)		(48		)
Total amounts reclassified, net of tax	$	85			$	85

^(a)  Included in interest charges.

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Other Income (Expense), Net (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Other Income and Expenses [Abstract]
Interest income	$ 13	$ 53	$ 45	$ 240
Other nonoperating income	65	2	110	0
Insurance policy income (expense)	78	(184)	(55)	(328)
Other income (expense), net	$ 156	$ (129)	$ 100	$ (88)

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Selected Balance Sheet Data Balance Sheet Related Disclosures, Inventories (Details) - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014
Public Utilities, Inventory [Line Items]
Inventories	$ 32,455	$ 43,231
Materials and supplies
Public Utilities, Inventory [Line Items]
Inventories	25,018	24,738
Fuel
Public Utilities, Inventory [Line Items]
Inventories	$ 7,437	$ 18,493

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Selected Balance Sheet Data Balance Sheet Related Disclosures, Property, Plant and Equipment (Details) - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014
Public Utility, Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	$ 5,871,790	$ 5,615,125
Less accumulated depreciation	(1,922,951)	(1,871,984)
Property, plant and equipment, net	3,948,839	3,743,141
Electric plant
Public Utility, Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	5,580,225	5,376,606
Construction work in progress
Public Utility, Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	$ 291,565	$ 238,519

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BALANCE SHEETS (UNAUDITED) (Parenthetical) - $ / shares	Jun. 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

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Income Taxes (Details) - USD ($)	3 Months Ended	6 Months Ended
	Sep. 30, 2012	Jun. 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		12,600,000	11,700,000
Total unrecognized tax benefit		14,200,000	13,200,000
NOL and tax credit carryforwards		(6,000,000)	$ (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]
Earliest year subject to examination		2009
Year(s) under examination	2010 and 2011
Year of carryback claim under examination	2009
Potential Tax Adjustments		$ 12,000,000
State Jurisdiction (Texas)
Tax Audits [Abstract]
Earliest year subject to examination		2009

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Fair Value of Financial Assets and Liabilities, Impact of Derivative Activity (Details) - USD ($)	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 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)	(100,000)	(100,000)
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	(1,200,000)	(1,000,000)	(2,000,000)	(2,400,000)
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities)	$ (1,700,000)	$ 1,900,000	$ (1,600,000)	$ (900,000)

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STATEMENTS OF INCOME (UNAUDITED) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Income Statement [Abstract]
Operating revenues	$ 422,985	$ 492,536	$ 846,814	$ 940,936
Operating expenses
Electric fuel and purchased power	243,026	314,146	488,825	603,350
Operating and maintenance expenses	73,827	68,963	147,724	138,361
Demand side management program expenses	2,760	2,849	6,429	5,913
Depreciation and amortization	36,750	35,071	72,489	65,583
Taxes (other than income taxes)	13,490	12,507	28,456	26,153
Total operating expenses	369,853	433,536	743,923	839,360
Operating income	53,132	59,000	102,891	101,576
Other income (expense), net	156	(129)	100	(88)
Allowance for funds used during construction — equity	1,788	2,895	3,493	6,535
Interest charges and financing costs
Interest charges — includes other financing costs of $771, $731, $1,544 and $1,461, respectively	21,074	19,645	41,958	38,926
Allowance for funds used during construction — debt	(1,137)	(1,721)	(2,198)	(3,848)
Total interest charges and financing costs	19,937	17,924	39,760	35,078
Income before income taxes	35,139	43,842	66,724	72,945
Income taxes	12,563	15,807	23,901	26,175
Net income	$ 22,576	$ 28,035	$ 42,823	$ 46,770

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Benefit Plans and Other Postretirement Benefits (Details) $ in Thousands	1 Months Ended	3 Months Ended		6 Months Ended
	Jan. 31, 2015 USD ($) Plan	Jun. 30, 2015 USD ($)	Jun. 30, 2014 USD ($)	Jun. 30, 2015 USD ($)	Jun. 30, 2014 USD ($)
Pension Benefits
Components of Net Periodic Benefit Cost (Credit) [Abstract]
Service cost		$ 2,751	$ 2,296	$ 5,503	$ 4,592
Interest cost		5,046	5,111	10,092	10,222
Expected return on plan assets		(7,152)	(6,545)	(14,305)	(13,090)
Amortization of prior service cost (credit)		10	13	20	27
Amortization of net loss (gain)		3,772	3,331	7,544	6,663
Net periodic benefit cost (credit)		4,427	4,206	8,854	8,414
Credits recognized (costs not recognized) due to the effects of regulation		686	708	1,399	1,415
Net benefit cost (credit) recognized for financial reporting		5,113	4,914	10,253	9,829
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		238	311	477	623
Interest cost		437	643	873	1,286
Expected return on plan assets		(635)	(811)	(1,270)	(1,623)
Amortization of prior service cost (credit)		(100)	(101)	(200)	(201)
Amortization of net loss (gain)		(160)	(81)	(320)	(161)
Net periodic benefit cost (credit)		(220)	(39)	(440)	(76)
Credits recognized (costs not recognized) due to the effects of regulation		0	0	0	0
Net benefit cost (credit) recognized for financial reporting		$ (220)	$ (39)	$ (440)	$ (76)
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

XML

STATEMENTS OF CASH FLOWS (UNAUDITED) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014
Operating activities
Net income	$ 42,823	$ 46,770
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	73,628	66,692
Demand side management program amortization	837	837
Deferred income taxes	11,866	51,678
Amortization of investment tax credits	(170)	(170)
Allowance for equity funds used during construction	(3,493)	(6,535)
Net derivative losses	133	133
Changes in operating assets and liabilities:
Accounts receivable	(19,478)	(15,131)
Accrued unbilled revenues	10,927	(33,034)
Inventories	10,776	2,022
Prepayments and other	(21,378)	(12,786)
Accounts payable	(10,210)	16,949
Net regulatory assets and liabilities	41,291	(34,055)
Other current liabilities	13,510	1,536
Pension and other employee benefit obligations	(10,435)	(3,122)
Change in other noncurrent assets	607	3,558
Change in other noncurrent liabilities	606	2,198
Net cash provided by operating activities	141,840	87,540
Investing activities
Utility capital/construction expenditures	(280,615)	(281,398)
Allowance for equity funds used during construction	3,493	6,535
Investments in utility money pool arrangement	(9,000)	(22,000)
Repayments from utility money pool arrangement	9,000	22,000
Net cash used in investing activities	(277,122)	(274,863)
Financing activities
Proceeds from (repayment of) short-term borrowings, net	172,000	15,000
Proceeds from Issuance of Long-term Debt	(85)	148,510
Borrowings under utility money pool arrangement	163,700	382,000
Repayments under utility money pool arrangement	(179,700)	(420,000)
Capital contributions from parent	34,535	100,000
Dividends paid to parent	(53,167)	(36,264)
Net cash provided by financing activities	137,283	189,246
Net change in cash and cash equivalents	2,001	1,923
Cash and cash equivalents at beginning of period	596	1,011
Cash and cash equivalents at end of period	2,597	2,934
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	(38,527)	(33,668)
Cash (paid) received for income taxes, net	(36,992)	8,705
Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable	$ 26,513	$ 22,423

XML

Commitments and Contingencies, Environmental Contingencies - Unrecorded Unconditional Purchase Obligation (Details) $ in Millions	1 Months Ended		6 Months Ended
	Dec. 31, 2014	Apr. 30, 2012 MW	Jun. 30, 2015 USD ($) MW	Apr. 30, 2015 USD ($)	Apr. 30, 2014 Issue
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 [Member]
Environmental Requirements [Abstract]
Generating capacity (in MW) | MW		25
Number of years before affected facilities must demonstrate compliance, low end of range		3 years
Number of years before affected facilities must demonstrate compliance, high end of range		4 years
Cost of capital incurred for installed mercury controls				$ 8.0
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 [Member]
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 by the Texas Commission on Environmental Quality			1
Capital Addition Purchase Commitments | Cross-State Air Pollution Rule
Environmental Requirements [Abstract]
Liability for estimated cost to comply with regulation, Maximum			$ 7.0
Capital Addition Purchase Commitments | Regional Haze Rules
Environmental Requirements [Abstract]
Liability for estimated cost to comply with regulation, Maximum			600.0
Estimated annual operating cost to comply with proposed regulation			$ 10.4

XML

Income Taxes (Tables)

6 Months Ended

Jun. 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)	June 30, 2015		Dec. 31, 2014
Unrecognized tax benefit — Permanent tax positions	$	1.6	$	1.5
Unrecognized tax benefit — Temporary tax positions	12.6		11.7
Total unrecognized tax benefit	$	14.2	$	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)	June 30, 2015			Dec. 31, 2014
NOL and tax credit carryforwards	$	(6.0	)	$	(4.8	)

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Borrowings and Other Financing Instruments, Short-Term Borrowings (Details) - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Jun. 30, 2015	Dec. 31, 2014
Short-term Debt [Line Items]
Amount outstanding at period end	$ 209,000	$ 37,000
Money Pool
Short-term Debt [Line Items]
Borrowing limit	100,000	100,000
Amount outstanding at period end	0	16,000
Average amount outstanding	4,000	9,000
Maximum amount outstanding	$ 36,000	$ 100,000
Weighted average interest rate, computed on a daily basis (percentage)	0.52%	0.22%
Weighted average interest rate at period end (percentage)		0.45%
Commercial Paper
Short-term Debt [Line Items]
Borrowing limit	$ 400,000	$ 400,000
Amount outstanding at period end	209,000	37,000
Average amount outstanding	160,000	83,000
Maximum amount outstanding	$ 209,000	$ 241,000
Weighted average interest rate, computed on a daily basis (percentage)	0.48%	0.26%
Weighted average interest rate at period end (percentage)	0.49%	0.47%

XML

Borrowings and Other Financing Instruments (Tables)

6 Months Ended

Jun. 30, 2015

Borrowings and Other Financing Instruments [Abstract]

Credit Facilities

At June 30, 2015, SPS had the following committed credit facility available (in millions of dollars):

Credit Facility (a)		Drawn(b)		Available
$	400	$	245	$	155

^(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 June 30, 2015			Twelve Months Ended Dec. 31, 2014
Borrowing limit	$	100		$	100
Amount outstanding at period end	—			16
Average amount outstanding	4			9
Maximum amount outstanding	36			100
Weighted average interest rate, computed on a daily basis	0.52		%	0.22		%
Weighted average interest rate at period end	N/A			0.45

Commercial Paper

Borrowings and Other Financing Instruments [Abstract]

Short-Term Borrowings

Commercial paper outstanding for SPS was as follows:

(Amounts in Millions, Except Interest Rates)	Three Months Ended June 30, 2015			Twelve Months Ended Dec. 31, 2014
Borrowing limit	$	400		$	400
Amount outstanding at period end	209			37
Average amount outstanding	160			83
Maximum amount outstanding	209			241
Weighted average interest rate, computed on a daily basis	0.48		%	0.26		%
Weighted average interest rate at period end	0.49			0.47

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BALANCE SHEETS (UNAUDITED) - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014
Current assets
Cash and cash equivalents	$ 2,597	$ 596
Accounts receivable, net	78,386	71,626
Accounts receivable from affiliates	14,701	1,983
Accrued unbilled revenues	118,360	129,287
Inventories	32,455	43,231
Regulatory assets	36,554	52,006
Derivative instruments	19,355	23,776
Deferred income taxes	91,672	51,854
Prepayments and other	52,854	31,476
Total current assets	446,934	405,835
Property, plant and equipment, net	3,948,839	3,743,141
Other assets
Regulatory assets	308,519	323,305
Derivative instruments	29,218	33,164
Other	14,918	15,859
Total other assets	352,655	372,328
Total assets	4,748,428	4,521,304
Current liabilities
Short-term debt	209,000	37,000
Borrowings under utility money pool arrangement	0	16,000
Accounts payable	148,722	160,762
Accounts payable to affiliates	14,970	19,790
Regulatory liabilities	115,316	87,723
Taxes accrued	24,017	27,208
Accrued interest	17,071	17,057
Dividends payable	23,025	27,828
Derivative instruments	3,565	3,565
Other	90,838	80,211
Total current liabilities	646,524	477,144
Deferred credits and other liabilities
Deferred income taxes	899,063	849,145
Regulatory liabilities	105,051	115,188
Asset retirement obligations	26,713	26,031
Derivative instruments	28,860	30,643
Pension and employee benefit obligations	93,166	103,670
Other	9,643	9,320
Total deferred credits and other liabilities	$ 1,162,496	$ 1,133,997
Commitments and contingencies
Capitalization
Long-term debt	$ 1,349,858	$ 1,349,691
Common stock — 200 shares authorized of $1.00 par value; 100 shares outstanding at June 30, 2015 and Dec. 31, 2014, respectively	0	0
Additional paid in capital	1,199,998	1,165,463
Retained earnings	390,456	395,998
Accumulated other comprehensive loss	(904)	(989)
Total common stockholder’s equity	1,589,550	1,560,472
Total liabilities and equity	$ 4,748,428	$ 4,521,304

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STATEMENTS OF INCOME (UNAUDITED) (Parenthetical) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Interest charges and financing costs
Other financing costs	$ 771	$ 731	$ 1,544	$ 1,461

XML

Fair Value of Financial Assets and Liabilities

6 Months Ended

Jun. 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 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 June 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 June 30, 2015 and Dec. 31, 2014:

(Amounts in Thousands) (a)	June 30, 2015	Dec. 31, 2014
Megawatt hours of electricity	13,620	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 each of the three and six months ended June 30, 2015 and 2014.

During the three and six months ended June 30, 2015, changes in the fair value of FTRs resulted in pre-tax net losses of $1.2 million and $2.0 million, respectively, recognized as regulatory assets and liabilities. For the three and six months ended June 30, 2014, changes in the fair value of FTRs resulted in pre-tax net losses of $1.0 million and $2.4 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 gains of $1.7 million and $1.6 million, respectively, were recognized for the three and six months ended June 30, 2015, respectively, recorded to electric fuel and purchased power. For the three and six months ended June 30, 2014, FTR settlement losses of $1.9 million and gains of $0.9 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 six months ended June 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 June 30, 2015, one of SPS’ eight most significant counterparties for these activities, comprising $9.6 million or 9 percent of this credit exposure, had investment grade credit ratings from Standard & Poor’s Ratings Services, Moody’s Investor Services or Fitch Ratings. Six of the eight most significant counterparties, comprising $58.5 million or 54 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 $1.3 million or 1 percent of this credit exposure, had credit quality less than investment grade, based on SPS’ internal analysis. All eight 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 June 30, 2015:

	June 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	$	—	$	—	$	21,533	$	21,533	$	(10,070	)	$	11,463
Total current derivative assets	$	—	$	—	$	21,533	$	21,533	$	(10,070	)	11,463
PPAs (a)												7,892
Current derivative instruments												$	19,355
Noncurrent derivative assets
PPAs (a)												$	29,218
Noncurrent derivative instruments												$	29,218
Current derivative liabilities
Other derivative instruments:
Electric commodity	$	—	$	—	$	10,070	$	10,070	$	(10,070	)	$	—
Total current derivative liabilities	$	—	$	—	$	10,070	$	10,070	$	(10,070	)	—
PPAs (a)												3,565
Current derivative instruments												$	3,565
Noncurrent derivative liabilities
PPAs (a)												$	28,860
Noncurrent derivative instruments												$	28,860

^(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 June 30, 2015. At June 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 six months ended June 30, 2015 and 2014:

	Three Months Ended June 30
(Thousands of Dollars)	2015			2014
Balance at April 1	$	6,457		$	5,791
Purchases	17,284			38,419
Settlements	(10,022		)	(13,554		)
Net transactions recorded during the period:
(Losses) Gains recognized as regulatory assets and liabilities	(2,256		)	3,286
Balance at June 30	$	11,463		$	33,942

	Six Months Ended June 30
(Thousands of Dollars)	2015			2014
Balance at Jan. 1	$	15,884		$	9,933
Purchases	22,213			39,475
Settlements	(18,400		)	(14,655		)
Net transactions recorded during the period:
Losses recognized as regulatory assets and liabilities	(8,234		)	(811		)
Balance at June 30	$	11,463		$	33,942

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 six months ended June 30, 2015 and 2014.

Fair Value of Long-Term Debt

As of June 30, 2015 and Dec. 31, 2014, other financial instruments for which the carrying amount did not equal fair value were as follows:

	June 30, 2015				Dec. 31, 2014
(Thousands of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion	$	1,349,858	$	1,491,780	$	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 June 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.

XML

Document and Entity Information - shares	6 Months Ended
	Jun. 30, 2015	Aug. 03, 2015
Document and Entity Information [Abstract]
Entity Registrant Name	SOUTHWESTERN PUBLIC SERVICE CO
Entity Central Index Key	0000092521
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Non-accelerated Filer
Document Type	10-Q
Document Period End Date	Jun. 30, 2015
Document Fiscal Year Focus	2015
Document Fiscal Period Focus	Q2
Amendment Flag	false
Entity Common Stock, Shares Outstanding		100

XML

Other Income (Expense), Net

6 Months Ended

Jun. 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 June 30					Six Months Ended June 30
(Thousands of Dollars)	2015		2014			2015			2014
Interest income	$	13	$	53		$	45		$	240
Other nonoperating income	65		2			110			—
Insurance policy income (expense)	78		(184		)	(55		)	(328		)
Other income (expense), net	$	156	$	(129	)	$	100		$	(88	)

XML

STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Comprehensive income:
Net income	$ 22,576	$ 28,035	$ 42,823	$ 46,770
Derivative instruments:
Reclassification of losses to net income, net of tax of $24 and $48 for each of the three and six months ended June 30, 2015 and 2014, respectively	43	42	85	85
Other comprehensive income	43	42	85	85
Comprehensive income	$ 22,619	$ 28,077	$ 42,908	$ 46,855

XML

Selected Balance Sheet Data

6 Months Ended

Jun. 30, 2015

Balance Sheet Related Disclosures [Abstract]

Selected Balance Sheet Data

Selected Balance Sheet Data

(Thousands of Dollars)	June 30, 2015			Dec. 31, 2014
Accounts receivable, net
Accounts receivable	$	84,326		$	77,465
Less allowance for bad debts	(5,940		)	(5,839		)
	$	78,386		$	71,626

(Thousands of Dollars)	June 30, 2015		Dec. 31, 2014
Inventories
Materials and supplies	$	25,018	$	24,738
Fuel	7,437		18,493
	$	32,455	$	43,231

(Thousands of Dollars)	June 30, 2015			Dec. 31, 2014
Property, plant and equipment, net
Electric plant	$	5,580,225		$	5,376,606
Construction work in progress	291,565			238,519
Total property, plant and equipment	5,871,790			5,615,125
Less accumulated depreciation	(1,922,951		)	(1,871,984		)
	$	3,948,839		$	3,743,141

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Accounting Pronouncements

6 Months Ended

Jun. 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 is currently evaluating the impact of adopting ASU 2015-02 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 (Accounting Standards Update (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.

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Rate Matters (Tables)

6 Months Ended

Jun. 30, 2015

Public Utilities, General Disclosures [Abstract]

SPS' Texas 2015 Electric Rate Case [Table Text Block]

In June 2015, SPS filed rebuttal testimony supporting a revised rate increase of approximately $42 million, or 4.4 percent.

										SPS Rebuttal Testimony
(Millions of Dollars)	AXM			OPUC			Staff
SPS’ revised rate request	$	58.9		$	58.9		$	58.9		$	58.9
Investment for capital expenditures — post-test year adjustments	(11.3		)	(23.8		)	(23.8		)	—
Lower ROE	(10.9		)	(13.5		)	(12.1		)	—
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		)
Depreciation expense	(13.3		)	—			—			—
Property taxes	—			(1.2		)	(4.4		)	(1.8		)
Revenue adjustments	(2.2		)	(0.2		)	—			—
Wholesale load reductions	(13.2		)	—			(11.1		)	—
Southwest Power Pool (SPP) transmission expansion plan	—			—			—			(7.3		)
Other, net	(1.7		)	(0.6		)	(2.2		)	(1.8		)
Total recommendation	$	(13.6	)	$	1.8		$	(2.6	)	$	46.4
Adjustment to move rate case expenses to a separate docket	—			—			—			(4.3		)
Recommendation, excluding rate case expenses	$	(13.6	)	$	1.8		$	(2.6	)	$	42.1

FERC Wholesale Rate Complaints [Table Text Block]

In the first half of 2015, Golden Spread, SPS and FERC staff filed their initial testimonies recommending the following ROEs:

	Refund Period		Production ROE		Transmission ROE (a)
Golden Spread (b)	1		8.78	%	9.28	%
	2		8.51		9.01
	3		8.45		8.95
SPS	1		10.25		10.39
	2		10.25		11.20
	3	(c)	10.40		11.20
FERC Staff	1		8.97		9.47
	2		8.64		9.14
	3		8.53		9.03

^(a)  Includes a SPP RTO membership adder up to 50 basis points.

^(b)  For the third refund period, the recommended production and transmission ROEs are supported by Golden Spread, certain New Mexico cooperatives and the West Texas Municipal Power Agency (transmission ROE only).

^(c)  In addition to the recommended ROEs,SPS also filed testimony recommending the ROEs remain unchanged.

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Benefit Plans and Other Postretirement Benefits

6 Months Ended

Jun. 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 June 30
	2015			2014			2015			2014
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Service cost	$	2,751		$	2,296		$	238		$	311
Interest cost	5,046			5,111			437			643
Expected return on plan assets	(7,152		)	(6,545		)	(635		)	(811		)
Amortization of prior service cost (credit)	10			13			(100		)	(101		)
Amortization of net loss (gain)	3,772			3,331			(160		)	(81		)
Net periodic benefit cost (credit)	4,427			4,206			(220		)	(39		)
Credits recognized due to the effects of regulation	686			708			—			—
Net benefit cost (credit) recognized for financial reporting	$	5,113		$	4,914		$	(220	)	$	(39	)

	Six Months Ended June 30
	2015			2014			2015			2014
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Service cost	$	5,503		$	4,592		$	477		$	623
Interest cost	10,092			10,222			873			1,286
Expected return on plan assets	(14,305		)	(13,090		)	(1,270		)	(1,623		)
Amortization of prior service cost (credit)	20			27			(200		)	(201		)
Amortization of net loss (gain)	7,544			6,663			(320		)	(161		)
Net periodic benefit cost (credit)	8,854			8,414			(440		)	(76		)
Credits recognized due to the effects of regulation	1,399			1,415			—			—
Net benefit cost (credit) recognized for financial reporting	$	10,253		$	9,829		$	(440	)	$	(76	)

In January 2015, contributions of $90.0 million were made across four of Xcel Energys pension plans, of which $11.6 million was attributable to SPS. Xcel Energy does not expect additional pension contributions during 2015.

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Commitments and Contingencies

6 Months Ended

Jun. 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 in SPS’ Annual Report on Form 10-K for the year ended Dec. 31, 2014 and in Notes 5 and 6 to SPS’ Quarterly Report on Form 10-Q for the quarterly period ended March 31, 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 June 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) 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 will go into effect beginning in August 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.

Air

Cross-State Air Pollution Rule (CSAPR) — CSAPR addresses long range transport of particulate matter (PM) and ozone by requiring reductions in sulfur dioxide (SO₂) 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 United States District Court of Appeals for the District of Columbia Circuit (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 cost approximately $7 million or less.

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. On June 29, 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 SO₂, 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 electric generating units (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 currently plans to issue its final rule in December 2015.

In May 2014, the EPA issued a request for information under the CAA related to SO₂ 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 SO₂ 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 SO₂ — The EPA adopted a more stringent NAAQS for SO₂ 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 SO₂ emissions. The Texas Commission on Environmental Quality (TCEQ) is expected to make recommendations for nonattainment areas to the EPA in September 2015 with a decision by summer 2016. 

If an area is designated nonattainment, the respective states will need to evaluate all SO₂ 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 SO₂ 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 SO₂ 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.

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.

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Income Taxes

6 Months Ended

Jun. 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. The statute of limitations applicable to Xcel Energy’s 2009 federal income tax return expires in March 2016. In the third quarter of 2012, the Internal Revenue Service (IRS) commenced an examination of tax years 2010 and 2011, including a 2009 carryback claim. As of June 30, 2015, the IRS had proposed an adjustment to the federal tax loss carryback claims that would result in $12 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 June 30, 2015, the IRS has begun the appeals process; however, the outcome and timing of a resolution are uncertain.

State Audits — SPS is a member of the Xcel Energy affiliated group that files consolidated state income tax returns. As of June 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)	June 30, 2015		Dec. 31, 2014
Unrecognized tax benefit — Permanent tax positions	$	1.6	$	1.5
Unrecognized tax benefit — Temporary tax positions	12.6		11.7
Total unrecognized tax benefit	$	14.2	$	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)	June 30, 2015			Dec. 31, 2014
NOL and tax credit carryforwards	$	(6.0	)	$	(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 progresses and state audits resume. As the IRS examination moves closer to completion, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $2 million.

The payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryforwards. The payables for interest related to unrecognized tax benefits at June 30, 2015 and Dec. 31, 2014 were not material. No amounts were accrued for penalties related to unrecognized tax benefits as of June 30, 2015 or Dec. 31, 2014.

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Rate Matters

6 Months Ended

Jun. 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 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 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 May 2015, several intervenors filed direct testimony in response to SPS’ rate request, including the Alliance of Xcel Municipalities (AXM), the Office of Public Utility Counsel (OPUC), and the PUCT Staff (Staff).

• AXM recommended a rate decrease of $13.6 million, an ROE of 9.40 percent and an equity ratio of 53.97 percent.

• The OPUC recommended a rate increase of $1.8 million, an ROE of 9.20 percent and an equity ratio of 52.38 percent.

• The Staff recommended a rate decrease of $2.6 million, an ROE of 9.30 percent and an equity ratio of 53.97 percent.

In June 2015, SPS filed rebuttal testimony supporting a revised rate increase of approximately $42 million, or 4.4 percent.

										SPS Rebuttal Testimony
(Millions of Dollars)	AXM			OPUC			Staff
SPS’ revised rate request	$	58.9		$	58.9		$	58.9		$	58.9
Investment for capital expenditures — post-test year adjustments	(11.3		)	(23.8		)	(23.8		)	—
Lower ROE	(10.9		)	(13.5		)	(12.1		)	—
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		)
Depreciation expense	(13.3		)	—			—			—
Property taxes	—			(1.2		)	(4.4		)	(1.8		)
Revenue adjustments	(2.2		)	(0.2		)	—			—
Wholesale load reductions	(13.2		)	—			(11.1		)	—
Southwest Power Pool (SPP) transmission expansion plan	—			—			—			(7.3		)
Other, net	(1.7		)	(0.6		)	(2.2		)	(1.8		)
Total recommendation	$	(13.6	)	$	1.8		$	(2.6	)	$	46.4
Adjustment to move rate case expenses to a separate docket	—			—			—			(4.3		)
Recommendation, excluding rate case expenses	$	(13.6	)	$	1.8		$	(2.6	)	$	42.1

New rates will be made effective retroactive to June 11, 2015 as established by the PUCT. Hearings were completed in July 2015. A PUCT decision is expected in the fourth quarter of 2015.

Pending Regulatory Proceedings — New Mexico Public Regulation Commission (NMPRC)

New Mexico 2015 Electric Rate Case — In June 2015, SPS filed an electric rate case with the NMPRC for an increase in non-fuel base rates of $31.5 million and a base fuel decrease of $30.1 million. The rate filing was based on a 2016 forecast test year (FTY), a requested return on equity of 10.25 percent, a jurisdictional electric rate base of $777.9 million and an equity ratio of 53.97 percent.

In June 2015, SPS’ rate case application was dismissed by the NMPRC.  The NMPRC determined that the filing did not comply with its new interpretation of the statute regarding FTY periods and the corresponding timing of a rate case submission in relation to the FTY used in the case. This new interpretation occurred during the recent Public Service Company of New Mexico rate case.

In July, SPS filed an appeal with the New Mexico Supreme Court. In addition, SPS plans to file a rate case later this year.

Pending and Recently Concluded Regulatory Proceedings — Federal Energy Regulatory Commission (FERC)

Wholesale Rate ROE Complaints— In April 2012, Golden Spread Electric Cooperative, Inc. (Golden Spread), a wholesale cooperative customer, 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 base formula rate ROE of 10.77 percent, are unjust and unreasonable, and asking that the 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 ROE in the SPS production formula rate for Golden Spread and transmission formula rates be reduced to 9.15 and 9.65 percent, respectively, effective July 19, 2013. In June 2014, the FERC issued orders consolidating the Golden Spread ROE complaints and setting the complaints for settlement judge or hearing procedures.

A third rate complaint was filed in October 2014 by Golden Spread, certain New Mexico cooperatives and the West Texas Municipal Power Agency, requesting that the ROE in certain SPS production formula rates for Golden Spread and the New Mexico cooperatives and transmission formula rates be reduced, this time 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. The FERC established effective dates for refunds of April 20, 2012 (first refund period), July 19, 2013 (second refund period) and Oct. 20, 2014 (third refund period), respectively.

SPS sought rehearing of the FERC decisions to allow back-to-back complaints involving the same issue with consecutive 15 month refund periods, asserting this ruling is contrary to the governing statute. On May 12, 2015, FERC denied the rehearing request as it pertained to the first two rate complaints. In July 2015, SPS filed an appeal to the D.C. Circuit Court of Appeals of the FERC orders in the first two rate complaints allowing the sequential complaints and consecutive 15 month refund periods. The D.C. Circuit Court has not established a procedural schedule. FERC action on the similar SPS rehearing request related to the third complaint is pending.

In the first half of 2015, Golden Spread, SPS and FERC staff filed their initial testimonies recommending the following ROEs:

	Refund Period		Production ROE		Transmission ROE (a)
Golden Spread (b)	1		8.78	%	9.28	%
	2		8.51		9.01
	3		8.45		8.95
SPS	1		10.25		10.39
	2		10.25		11.20
	3	(c)	10.40		11.20
FERC Staff	1		8.97		9.47
	2		8.64		9.14
	3		8.53		9.03

^(a)  Includes a SPP RTO membership adder up to 50 basis points.

^(b)  For the third refund period, the recommended production and transmission ROEs are supported by Golden Spread, certain New Mexico cooperatives and the West Texas Municipal Power Agency (transmission ROE only).

^(c)  In addition to the recommended ROEs,SPS also filed testimony recommending the ROEs remain unchanged.

Hearings scheduled for July 2015 for the first two rate complaints were canceled and the parties agreed to file briefs based on pre-filed testimony. An initial ALJ decision on the first two complaints is expected to be issued by Nov. 25, 2015, and a final FERC order to be issued no earlier than 2016. A hearing for the third rate complaint is scheduled for Oct. 2015, with an ALJ initial decision expected in January 2016 and a final FERC order no earlier than later in 2016.

SPS recorded a current liability representing the current best estimate of a refund obligation associated with potential ROE adjustments as of June 30, 2015, and is reducing transmission and production revenues, net of expense, between $4 million and $6 million annually.

2004 FERC Complaint Case Orders—In August 2013, the FERC issued an order related to a 2004 complaint case brought by Golden Spread and Public Service Company of New Mexico (PNM) and an Order on Initial Decision in a subsequent 2006 production rate case filed by SPS.

The original complaint included two key components: 1) PNM’s claim regarding inappropriate allocation of fuel costs and 2) a base rate complaint, including the appropriate demand-related cost allocator. The FERC previously determined that the allocation of fuel costs and the demand-related cost allocator utilized by SPS was appropriate.

In the August 2013 Orders, the FERC clarified its previous ruling on the allocation of fuel costs and reaffirmed that the refunds in question should only apply to firm requirements customers and not PNM’s contractual load. The FERC also reversed its prior demand-related cost allocator decision. The FERC stated that it had erred in its initial analysis and concluded that the SPS system was a 3 coincident peak (CP) rather than a 12 CP system.

In September 2013, SPS filed a request for rehearing of the FERC ruling on the CP allocation and refund decisions. SPS asserted that the FERC applied an improper burden of proof and that precedent did not support retroactive refunds. PNM also requested rehearing of the FERC decision not to reverse its prior ruling. In October 2013, the FERC issued orders further considering the requests for rehearing, which are currently pending. As of Dec. 31, 2014, SPS had accrued $50.4 million related to the August 2013 Orders and an additional $1.5 million of principal and interest has been accrued during 2015.

2015 Production Formula Rate Change Filing—In January 2015, SPS filed to revise the production formula rates for six of its wholesale customers, including Golden Spread, certain New Mexico cooperatives and West Texas Municipal Power Agency, effective Feb. 1, 2015. The filing proposes several modifications, including a reduction in wholesale depreciation rates and the use of a 12 CP demand-related cost allocator for all wholesale customers. In March 2015, the FERC accepted this filing, effective July 1, 2015, subject to refund and settlement judge or hearing procedures. The parties remain engaged in settlement judge procedures. Effective June 1, 2015, the Golden Spread contract demand quantity subject to the formula rate change declined from 500 MW to 300 MW.

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Borrowings and Other Financing Instruments

6 Months Ended

Jun. 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 June 30, 2015			Twelve Months Ended Dec. 31, 2014
Borrowing limit	$	100		$	100
Amount outstanding at period end	—			16
Average amount outstanding	4			9
Maximum amount outstanding	36			100
Weighted average interest rate, computed on a daily basis	0.52		%	0.22		%
Weighted average interest rate at period end	N/A			0.45

Commercial Paper — SPS meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under its credit facility. Commercial paper outstanding for SPS was as follows:

(Amounts in Millions, Except Interest Rates)	Three Months Ended June 30, 2015			Twelve Months Ended Dec. 31, 2014
Borrowing limit	$	400		$	400
Amount outstanding at period end	209			37
Average amount outstanding	160			83
Maximum amount outstanding	209			241
Weighted average interest rate, computed on a daily basis	0.48		%	0.26		%
Weighted average interest rate at period end	0.49			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 June 30, 2015 and Dec. 31, 2014, there were $36.0 million and $30.0 million of letters of credit outstanding, respectively under the credit facility. The contract amounts of these letters of credit approximate their fair value and are subject to fees.

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

At June 30, 2015, SPS had the following committed credit facility available (in millions of dollars):

Credit Facility (a)		Drawn(b)		Available
$	400	$	245	$	155

^(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 June 30, 2015 and Dec. 31, 2014.

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Commitments and Contingencies, Purchased Power Agreements (Details) - Independent Power Producing Entities - MW	3 Months Ended	12 Months Ended
	Jun. 30, 2015	Dec. 31, 2014
Purchased Power Agreements [Abstract]
Generating capacity (in MW)	827	827
Purchase Power Agreement Duration, Maximum (year)	2033	2033

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Selected Balance Sheet Data (Tables)

6 Months Ended

Jun. 30, 2015

Balance Sheet Related Disclosures [Abstract]

Accounts Receivable, Net

(Thousands of Dollars)	June 30, 2015			Dec. 31, 2014
Accounts receivable, net
Accounts receivable	$	84,326		$	77,465
Less allowance for bad debts	(5,940		)	(5,839		)
	$	78,386		$	71,626

Inventories

(Thousands of Dollars)	June 30, 2015		Dec. 31, 2014
Inventories
Materials and supplies	$	25,018	$	24,738
Fuel	7,437		18,493
	$	32,455	$	43,231

Property, Plant and Equipment, Net

(Thousands of Dollars)	June 30, 2015			Dec. 31, 2014
Property, plant and equipment, net
Electric plant	$	5,580,225		$	5,376,606
Construction work in progress	291,565			238,519
Total property, plant and equipment	5,871,790			5,615,125
Less accumulated depreciation	(1,922,951		)	(1,871,984		)
	$	3,948,839		$	3,743,141

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Other Income (Expense), Net (Tables)

6 Months Ended

Jun. 30, 2015

Other Income and Expenses [Abstract]

Other Income (Expense), Net

Other income (expense), net consisted of the following:

	Three Months Ended June 30					Six Months Ended June 30
(Thousands of Dollars)	2015		2014			2015			2014
Interest income	$	13	$	53		$	45		$	240
Other nonoperating income	65		2			110			—
Insurance policy income (expense)	78		(184		)	(55		)	(328		)
Other income (expense), net	$	156	$	(129	)	$	100		$	(88	)

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Fair Value of Financial Assets and Liabilities, Fair Value Measurements (Details) - USD ($)	Jun. 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	19,355,000		23,776,000
Other Noncurrent Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	29,218,000		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	28,860,000		30,643,000
Fair Value Measured on a Recurring Basis | Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	11,463,000		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	11,463,000		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	21,533,000		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	21,533,000		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	10,070,000		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	10,070,000		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	21,533,000		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	21,533,000		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	10,070,000		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	10,070,000		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	(10,070,000)	[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	(10,070,000)	[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	(10,070,000)	[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	(10,070,000)	[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	29,218,000	[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	$ 28,860,000	[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 June 30, 2015. At June 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

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STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED) (Parenthetical) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Derivative instruments:
Reclassification of losses to net income, tax	$ 24	$ 24	$ 48	$ 48

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Summary of Significant Accounting Policies

6 Months Ended

Jun. 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.

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Benefit Plans and Other Postretirement Benefits (Tables)

6 Months Ended

Jun. 30, 2015

Compensation and Retirement Disclosure [Abstract]

Components of Net Periodic Benefit Cost (Credit)

Components of Net Periodic Benefit Cost (Credit)

	Three Months Ended June 30
	2015			2014			2015			2014
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Service cost	$	2,751		$	2,296		$	238		$	311
Interest cost	5,046			5,111			437			643
Expected return on plan assets	(7,152		)	(6,545		)	(635		)	(811		)
Amortization of prior service cost (credit)	10			13			(100		)	(101		)
Amortization of net loss (gain)	3,772			3,331			(160		)	(81		)
Net periodic benefit cost (credit)	4,427			4,206			(220		)	(39		)
Credits recognized due to the effects of regulation	686			708			—			—
Net benefit cost (credit) recognized for financial reporting	$	5,113		$	4,914		$	(220	)	$	(39	)

	Six Months Ended June 30
	2015			2014			2015			2014
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Service cost	$	5,503		$	4,592		$	477		$	623
Interest cost	10,092			10,222			873			1,286
Expected return on plan assets	(14,305		)	(13,090		)	(1,270		)	(1,623		)
Amortization of prior service cost (credit)	20			27			(200		)	(201		)
Amortization of net loss (gain)	7,544			6,663			(320		)	(161		)
Net periodic benefit cost (credit)	8,854			8,414			(440		)	(76		)
Credits recognized due to the effects of regulation	1,399			1,415			—			—
Net benefit cost (credit) recognized for financial reporting	$	10,253		$	9,829		$	(440	)	$	(76	)

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Borrowings and Other Financing Instruments, Credit Facility (Details) - Credit Facility		Jun. 30, 2015 USD ($)
Line of Credit Facility [Line Items]
Credit Facility	[1]	$ 400,000,000
Drawn	[2]	245,000,000
Available		155,000,000
Direct advances on the credit facility outstanding		$ 0

[1] This credit facility expires in October 2019.

[2] Includes outstanding commercial paper and letters of credit.

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Other Comprehensive Income

6 Months Ended

Jun. 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 six months ended June 30, 2015 and 2014 were as follows:

	Gains and Losses on Cash Flow Hedges
(Thousands of Dollars)	Three Months Ended June 30, 2015			Three Months Ended June 30, 2014
Accumulated other comprehensive loss at April 1	$	(947	)	$	(1,118	)
Losses reclassified from net accumulated other comprehensive loss	43			42
Net current period other comprehensive income	43			42
Accumulated other comprehensive loss at June 30	$	(904	)	$	(1,076	)

	Gains and Losses on Cash Flow Hedges
(Thousands of Dollars)	Six Months Ended June 30, 2015			Six Months Ended June 30, 2014
Accumulated other comprehensive loss at Jan. 1	$	(989	)	$	(1,161	)
Losses reclassified from net accumulated other comprehensive loss	85			85
Net current period other comprehensive income	85			85
Accumulated other comprehensive loss at June 30	$	(904	)	$	(1,076	)

Reclassifications from accumulated other comprehensive loss for the three and six months ended June 30, 2015 and 2014 were as follows:

	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Three Months Ended June 30, 2015				Three Months Ended June 30, 2014
Losses on cash flow hedges:
Interest rate derivatives	$	67		(a)	$	66		(a)
Total, pre-tax	67				66
Tax benefit	(24		)		(24		)
Total amounts reclassified, net of tax	$	43			$	42

	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Six Months Ended June 30, 2015				Six Months Ended June 30, 2014
Losses on cash flow hedges:
Interest rate derivatives	$	133		(a)	$	133		(a)
Total, pre-tax	133				133
Tax benefit	(48		)		(48		)
Total amounts reclassified, net of tax	$	85			$	85

^(a)  Included in interest charges.