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, 2016

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 August 4, 2016
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	24
PART II — OTHER INFORMATION
Item 1     —	Legal Proceedings	25
Item 1A  —	Risk Factors	25
Item 4    —	Mine Safety Disclosures	25
Item 5    —	Other Information	25
Item 6    —	Exhibits	25
SIGNATURES		26
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
	2016			2015			2016			2015
Operating revenues	$	440,445		$	422,985		$	831,284		$	846,814
Operating expenses
Electric fuel and purchased power	246,547			243,026			459,950			488,825
Operating and maintenance expenses	66,588			73,827			130,711			147,724
Demand side management program expenses	3,239			2,760			6,616			6,429
Depreciation and amortization	40,893			36,750			81,224			72,489
Taxes (other than income taxes)	14,792			13,490			30,828			28,456
Total operating expenses	372,059			369,853			709,329			743,923
Operating income	68,386			53,132			121,955			102,891
Other income, net	392			156			426			100
Allowance for funds used during construction — equity	2,379			1,788			4,716			3,493
Interest charges and financing costs
Interest charges — includes other financing costs of $813, $771, $1,633 and $1,544, respectively	22,075			21,074			44,007			41,958
Allowance for funds used during construction — debt	(1,397		)	(1,137		)	(2,724		)	(2,198		)
Total interest charges and financing costs	20,678			19,937			41,283			39,760
Income before income taxes	50,479			35,139			85,814			66,724
Income taxes	18,268			12,563			31,080			23,901
Net income	$	32,211		$	22,576		$	54,734		$	42,823

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
	2016		2015		2016		2015
Net income	$	32,211	$	22,576	$	54,734	$	42,823
Other comprehensive income
Pension and retiree medical benefits:
Amortization of losses included in net periodic benefit cost,     net of tax of $6, $0, $13 and $0, respectively	11		—		23		—
Derivative instruments:
Reclassification of losses to net income, net of tax of $24,     $24, $49 and $48, respectively	43		43		85		85
Other comprehensive income	54		43		108		85
Comprehensive income	$	32,265	$	22,619	$	54,842	$	42,908

See Notes to Financial Statements

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SOUTHWESTERN PUBLIC SERVICE COMPANY

STATEMENTS OF CASH FLOWS (UNAUDITED)

(amounts in thousands)

	Six Months Ended June 30
	2016			2015
Operating activities
Net income	$	54,734		$	42,823
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	81,600			73,628
Demand side management program amortization	837			837
Deferred income taxes	53,217			11,866
Amortization of investment tax credits	(106		)	(170		)
Allowance for equity funds used during construction	(4,716		)	(3,493		)
Net derivative losses	134			133
Changes in operating assets and liabilities:
Accounts receivable	(12,997		)	(19,478		)
Accrued unbilled revenues	(25,690		)	10,927
Inventories	5,889			10,776
Prepayments and other	30,189			(21,378		)
Accounts payable	9,888			(10,210		)
Net regulatory assets and liabilities	(3,216		)	41,291
Other current liabilities	(4,862		)	13,510
Pension and other employee benefit obligations	(16,357		)	(10,435		)
Change in other noncurrent assets	(373		)	607
Change in other noncurrent liabilities	2,693			606
Net cash provided by operating activities	170,864			141,840
Investing activities
Utility capital/construction expenditures	(263,653		)	(280,615		)
Proceeds from insurance recoveries	987			—
Allowance for equity funds used during construction	4,716			3,493
Investments in utility money pool arrangement	—			(9,000		)
Repayments from utility money pool arrangement	—			9,000
Other	(1,174		)	—
Net cash used in investing activities	(259,124		)	(277,122		)
Financing activities
Proceeds from short-term borrowings, net	10,000			172,000
Repayment of long-term debt	—			(85		)
Borrowings under utility money pool arrangement	391,000			163,700
Repayments under utility money pool arrangement	(291,000		)	(179,700		)
Capital contributions from parent	16,225			34,535
Dividends paid to parent	(38,182		)	(53,167		)
Net cash provided by financing activities	88,043			137,283
Net change in cash and cash equivalents	(217		)	2,001
Cash and cash equivalents at beginning of period	834			596
Cash and cash equivalents at end of period	$	617		$	2,597
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	(39,960	)	$	(38,527	)
Cash received (paid) for income taxes, net	41,170			(36,992		)
Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable	$	30,172		$	26,513

See Notes to Financial Statements

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SOUTHWESTERN PUBLIC SERVICE COMPANY

BALANCE SHEETS (UNAUDITED)

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

	June 30, 2016			Dec. 31, 2015
Assets
Current assets
Cash and cash equivalents	$	617		$	834
Accounts receivable, net	84,008			71,166
Accounts receivable from affiliates	1,234			1,079
Accrued unbilled revenues	129,471			103,781
Inventories	31,657			37,546
Regulatory assets	30,656			31,541
Derivative instruments	6,596			12,952
Deferred income taxes	39,747			35,686
Prepaid taxes	16,573			35,666
Prepayments and other	8,436			20,520
Total current assets	348,995			350,771
Property, plant and equipment, net	4,520,672			4,348,823
Other assets
Regulatory assets	304,345			301,814
Derivative instruments	23,692			25,272
Other	4,997			3,449
Total other assets	333,034			330,535
Total assets	$	5,202,701		$	5,030,129
Liabilities and Equity
Current liabilities
Current portion of long-term debt	$	200,000		$	200,000
Short-term debt	25,000			15,000
Borrowings under utility money pool arrangement	100,000			—
Accounts payable	155,556			146,794
Accounts payable to affiliates	13,073			29,135
Regulatory liabilities	84,499			98,305
Taxes accrued	31,413			33,374
Accrued interest	17,666			17,781
Dividends payable	19,388			12,538
Derivative instruments	3,565			3,565
Other	31,262			35,654
Total current liabilities	681,422			592,146
Deferred credits and other liabilities
Deferred income taxes	953,522			896,430
Regulatory liabilities	235,479			229,584
Asset retirement obligations	27,949			27,233
Derivative instruments	25,296			27,078
Pension and employee benefit obligations	76,825			93,346
Other	20,272			17,841
Total deferred credits and other liabilities	1,339,343			1,291,512
Commitments and contingencies
Capitalization
Long-term debt	1,339,177			1,338,522
Common stock — 200 shares authorized of $1.00 par value; 100 shares outstanding at June 30, 2016 and Dec. 31, 2015, respectively	—			—
Additional paid in capital	1,396,223			1,371,223
Retained earnings	447,709			438,007
Accumulated other comprehensive loss	(1,173		)	(1,281		)
Total common stockholder’s equity	1,842,759			1,807,949
Total liabilities and equity	$	5,202,701		$	5,030,129

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, 2016, and Dec. 31, 2015; the results of its operations, including the components of net income and comprehensive income, for the three and six months ended June 30, 2016 and 2015; and its cash flows for the six months endedJune 30, 2016 and 2015. All adjustments are of a normal, recurring nature, except as otherwise disclosed. Management has also evaluated the impact of events occurring after June 30, 2016 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, 2015 balance sheet information has been derived from the audited 2015 financial statements included in the SPS Annual Report on Form 10-K for the year ended Dec. 31, 2015. 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, 2015, filed with the SEC on Feb. 22, 2016. 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, 2015, 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. 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.

Presentation of Deferred Taxes — In November 2015, the FASB issued Balance Sheet Classification of Deferred Taxes, Topic 740 (ASU No 2015-17), which eliminates the requirement to present deferred tax assets and liabilities as current and noncurrent on the balance sheet based on the classification of the related asset or liability, and instead requires classification of all deferred tax assets and liabilities as noncurrent. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, 2016, and early adoption is permitted. Other than the prescribed classification of all deferred tax assets and liabilities as noncurrent, SPS does not expect the implementation of ASU 2015-17 to have a material impact on its financial statements.

Classification and Measurement of Financial Instruments — In January 2016, the FASB issued Recognition and Measurement of Financial Assets and Financial Liabilities, Subtopic 825-10 (ASU No. 2016-01), which among other changes in accounting and disclosure requirements, replaces the cost method of accounting for non-marketable equity securities with a model for recognizing impairments and observable price changes, and also eliminates the available-for-sale classification for marketable equity securities. Under the new guidance, other than when the consolidation or equity method of accounting is utilized, changes in the fair value of equity securities are to be recognized in earnings. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, 2017. SPS is currently evaluating the impact of adopting ASU 2016-01 on its financial statements.

Leases — In February 2016, the FASB issued Leases, Topic 842 (ASU No. 2016-02), which, for lessees, requires balance sheet recognition of right-of-use assets and lease liabilities for all leases. Additionally, for leases that qualify as finance leases, the guidance requires expense recognition consisting of amortization of the right-of-use asset as well as interest on the related lease liability using the effective interest method. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, 2018, and early adoption is permitted. SPS is currently evaluating the impact of adopting ASU 2016-02 on its financial statements.

7

Stock Compensation — In March 2016, the FASB issued Improvements to Employee Share-Based Payment Accounting, Topic 718 (ASU 2016-09), which amends existing guidance to simplify several aspects of accounting and presentation for share-based payment transactions, including the accounting for income taxes and forfeitures, as well as presentation in the statement of cash flows. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, 2016, and early adoption is permitted. SPS does not expect the implementation of ASU 2016-09 to have a material impact on its financial statements.

Recently Adopted

Consolidation— In February 2015, the FASB issued Amendments to the Consolidation Analysis, Topic 810 (ASU No. 2015-02), which reduces the number of consolidation models and amends certain consolidation principles related to variable interest entities. SPS implemented the guidance on Jan. 1, 2016, and the implementation did not have a significant impact on its financial statements.

Presentation of Debt Issuance Costs— In April 2015, the FASB issued Simplifying the Presentation of Debt Issuance Costs, Subtopic 835-30 (ASU No. 2015-03), which requires the presentation of debt issuance costs on the balance sheet as a deduction from the carrying amount of the related debt, instead of presentation as an asset. SPS implemented the new guidance as required on Jan. 1, 2016, and as a result, $11.8 million of deferred debt issuance costs were presented as a deduction from the carrying amount of long-term debt on the balance sheet as of March 31, 2016, and $12.1 million of such deferred costs were retrospectively reclassified from other non-current assets to long-term debt on the balance sheet as of Dec. 31, 2015.

Fair Value Measurement— In May 2015, the FASB issued Disclosures for Investments in Certain Entities that Calculate Net Asset Value per Share (or Its Equivalent), Topic 820 (ASU No. 2015-07), which eliminates the requirement to categorize fair value measurements using a net asset value methodology in the fair value hierarchy. SPS implemented the guidance on Jan. 1, 2016, and the implementation did not have a material impact on its financial statements.

3. Selected Balance Sheet Data

(Thousands of Dollars)	June 30, 2016			Dec. 31, 2015
Accounts receivable, net
Accounts receivable	$	89,872		$	77,054
Less allowance for bad debts	(5,864		)	(5,888		)
	$	84,008		$	71,166

(Thousands of Dollars)	June 30, 2016		Dec. 31, 2015
Inventories
Materials and supplies	$	25,525	$	24,888
Fuel	6,132		12,658
	$	31,657	$	37,546

(Thousands of Dollars)	June 30, 2016			Dec. 31, 2015
Property, plant and equipment, net
Electric plant	$	6,119,713		$	5,933,764
Construction work in progress	277,974			236,697
Total property, plant and equipment	6,397,687			6,170,461
Less accumulated depreciation	(1,877,015		)	(1,821,638		)
	$	4,520,672		$	4,348,823

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, 2015 appropriately represents, in all material respects, the current status of other income tax matters, and are incorporated herein by reference.

8

Federal Audit — SPS is a member of the Xcel Energy affiliated group that files a consolidated federal income tax return. In 2012, the Internal Revenue Service (IRS) commenced an examination of tax years 2010 and 2011, including the 2009 carryback claim. As of June 30, 2016, the IRS had proposed an adjustment to the federal tax loss carryback claims that would result in $14 million of income tax expense for the 2009 through 2011 and 2013 claims, the recently filed 2014 claim, and the anticipated claim for 2015. SPS is not expected to accrue any income tax expense related to this adjustment. In the fourth quarter of 2015, the IRS forwarded the issue to the Office of Appeals (Appeals). During the second quarter of 2016 the IRS audit team presented their case to Appeals; however, the outcome and timing of a resolution are uncertain. The statute of limitations applicable to Xcel Energy’s 2009 through 2011 federal income tax returns expires in December 2016 following an extension to allow additional time for the Appeals process. In the third quarter of 2015, the IRS commenced an examination of tax years 2012 and 2013. As of June 30, 2016, the IRS had not proposed any material adjustments to tax years 2012 and 2013.

State Audits — SPS is a member of the Xcel Energy affiliated group that files consolidated state income tax returns. As of June 30, 2016, SPS’ earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations is 2009. In February 2016, Texas began an audit of years 2009 and 2010. As of June 30, 2016, Texas had not proposed any adjustments, and there were no other state income tax audits in progress.

Unrecognized Tax Benefits — The unrecognized tax benefit balance includes permanent tax positions, which if recognized would affect the annual 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, 2016		Dec. 31, 2015
Unrecognized tax benefit — Permanent tax positions	$	2.7	$	2.6
Unrecognized tax benefit — Temporary tax positions	21.9		22.1
Total unrecognized tax benefit	$	24.6	$	24.7

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, 2016			Dec. 31, 2015
NOL and tax credit carryforwards	$	(5.2	)	$	(5.0	)

It is reasonably possible that SPS’ amount of unrecognized tax benefits could significantly change in the next 12 months as the IRS Appeals and audit progress, the Texas audit progresses, and other state audits resume. As the IRS Appeals, IRS audit, and Texas audit progress, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $7 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, 2016 and Dec. 31, 2015 were not material. No amounts were accrued for penalties related to unrecognized tax benefits as of June 30, 2016 or Dec. 31, 2015.

9

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, 2015, appropriately represent, in all material respects, the current status of other rate matters, and are incorporated herein by reference.

Pending Regulatory Proceedings — Public Utility Commission of Texas (PUCT)

Appeal of the Texas 2015 Electric Rate Case Decision — In April 2016, SPS filed an appeal, with the Texas State District Court, of the PUCT’s order that had denied SPS’ request for rehearing on certain items in SPS’ Texas 2015 electric rate case related to capital structure, incentive compensation and wholesale load reductions.

In 2014, SPS had requested an overall retail electric revenue rate increase of $64.8 million, which it subsequently revised to $42.1 million. In 2015, the PUCT approved an overall rate decrease of approximately $4.0 million, net of rate case expenses.

The hearing in the appeal is scheduled for February 2017.

Texas 2015 Electric Rate Net Refund Case — Under an agreement in the Texas 2015 electric rate case, the final rates were retroactively applied to June 11, 2015. In June 2016, SPS filed an application to provide a net refund of approximately $1.25 million to reflect the difference in revenue SPS would have received for usage had SPS been charging the final rates approved by the PUCT from June 11, 2015 through Jan. 31, 2016. SPS has proposed to make the net refund over a six-month period beginning October 2016. The application is pending before the PUCT.

Texas 2016 Electric Rate Case — In February 2016, SPS filed a retail electric, non-fuel rate case in Texas with each of its Texas municipalities and the PUCT requesting an overall increase in annual base rate revenue of approximately $71.9 million, or 14.4 percent. The filing is based on a historic test year (HTY) ended Sept. 30, 2015, a requested return on equity (ROE) of 10.25 percent, an electric rate base of approximately $1.7 billion, and an equity ratio of 53.97 percent. In April 2016, SPS revised its requested rate increase to $68.6 million.

The following table summarizes the revised net request:

(Millions of Dollars)	Request
Capital expenditure investments	$	38.9
Change in jurisdictional allocation factors	9.8
Changes in ROE and capital structure	11.6
Estimated rate case expenses	4.5
Other, net	3.8
Total	$	68.6

Key dates in the procedural schedule are as follows:

• Intervenor direct testimony — Aug. 16, 2016;

• PUCT Staff direct testimony — Aug. 23, 2016;

• PUCT Staff and Intervenors’ cross-rebuttal testimony — Sept. 7, 2016;

• SPS’ rebuttal testimony — Sept. 9, 2016; and

• Hearings — Sept. 27 - Oct. 7, 2016.

SPS and various parties are having discussions regarding a potential settlement of the rate case. The final rates established at the end of the case are expected to be effective retroactive to July 20, 2016. A PUCT decision is expected in the first quarter of 2017.

10

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

New Mexico 2015 Electric Rate Case — In October 2015, SPS filed an electric rate case with the NMPRC seeking an increase in non-fuel base rates of $45.4 million. The proposed increase would be offset by a decrease in base fuel revenue of approximately $21.1 million. The rate filing is based on a June 30, 2015 HTY adjusted for known and measurable changes, a requested ROE of 10.25 percent, an electric rate base of approximately $734 million and an equity ratio of 53.97 percent.

In May 2016, SPS, the NMPRC Staff and all other parties filed a unanimous black-box stipulation that resolves all issues in the case. Under the stipulation, SPS will implement a non-fuel base rate increase of $23.5 million and a decrease in base fuel revenue of approximately $21.1 million. The decrease in base fuel revenue will be reflected in adjustments collected through the fuel and purchased power cost adjustment clause. The stipulation places no restriction on when SPS may file its next base rate case.

In July 2016, the hearing examiner issued a recommendation that the NMPRC approve the stipulation. The stipulation is subject to approval by the NMPRC and a decision on the settlement and implementation of final rates is expected in fall of 2016.

Pending Regulatory Proceedings — Federal Energy Regulatory Commission (FERC)

Southwest Power Pool, Inc. (SPP) Open Access Transmission Tariff (OATT) Upgrade Costs — Under the SPP OATT, costs of participant-funded, or “sponsored,” transmission upgrades may be recovered, in part, from other SPP customers whose transmission service depends on capacity enabled by the upgrade.  The SPP OATT has allowed SPP to collect charges since 2008, but to date SPP has not charged its customers any amounts attributable to these upgrades. 

In April 2016, SPP filed a request with the FERC for a waiver that would allow SPP to recover the charges not billed since 2008.  The FERC approved the waiver request in July 2016.  SPS is considering whether to seek clarification or rehearing of the FERC order.  SPP has indicated it anticipates completing its process and invoicing customers during the fourth quarter of 2016.  SPS estimates the charges to be $5 million to $10 million, based on preliminary information. SPS anticipates these costs would be recoverable through regulatory mechanisms.

6. Commitments and Contingencies

Except to the extent noted below and in Note 5 above, the circumstances set forth in Notes 10 and 11 to the financial statements included in SPS’ Annual Report on Form 10-K for the year ended Dec. 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, 2016 and Dec. 31, 2015, 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

Air

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 United States Environmental Protection Agency (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 national parks and wilderness areas. Under BART, regional haze plans identify facilities that will have to reduce sulfur dioxide (SO₂), nitrogen oxide (NOx) and particulate matter (PM) emissions and set emission limits for those facilities. BART requirements can also be met through participation in interstate emission trading programs such as the Clean Air Interstate Rule (CAIR) and its successor, Cross-State Air Pollution Rule (CSAPR).

Texas developed a state implementation plan (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 December 2014, the EPA proposed to approve the BART portion of the SIP, with the exception that the EPA would substitute the CSAPR compliance for Texas’ reliance on CAIR. In January 2016, the EPA adopted a final rule that defers its approval of CSAPR compliance as BART until the EPA considers further adjustments to CSAPR emission budgets under the United States Court of Appeals for the District of Columbia Circuit’s (D.C. Circuit) remand of the Texas SO₂ emission budgets. In March 2016, the EPA requested information under the Clean Air Act (CAA) related to EGUs at SPS’ plants. SPS identified Harrington Units 1 and 2, Jones Units 1 and 2, Nichols Unit 3 and Plant X Unit 4 as BART-eligible units. These units will be evaluated based on their impact on visibility. Additional emission control equipment under the EPA’s BART guidelines for PM, SO₂ and NOx could be required if a unit is determined to “cause or contribute” to visibility impairment. SPS cannot evaluate the impact of additional emission controls until the EPA concludes its evaluation of BART. The EPA is expected to issue a proposed rule in December 2016. In June 2016, the EPA issued a memorandum which allows Texas to voluntarily adopt the CSAPR emission budgets limiting annual SO₂ and NOx emissions and rely on those emission budgets to satisfy Texas’ BART obligations under the regional haze rules. It is not yet known whether the Texas Commission on Environmental Quality (TCEQ) intends to utilize this option.

In December 2014, the EPA proposed to disapprove the reasonable progress portions of the SIP and instead adopt a federal implementation plan (FIP). In January 2016, the EPA adopted a final rule establishing a FIP for the state of Texas. As part of this final rule, the EPA imposed SO₂ emission limitations that reflect the installation of dry scrubbers on Tolk Units 1 and 2, with compliance required by February 2021. Investment costs associated with dry scrubbers could be approximately $600 million. In March 2016, SPS appealed the EPA’s decision and asked for a stay of the final rule while it is being reviewed. In July 2016, the United States Court of Appeals for the Fifth Circuit (Fifth Circuit) granted the stay motion and decided that the Fifth Circuit, not the D.C. Circuit, is the appropriate venue for this case. In addition, SPS filed a petition with the EPA requesting reconsideration of the final rule. SPS believes these costs would be recoverable through regulatory mechanisms if required, 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. 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. In June 2016, the EPA issued final designations which found the area near the Tolk plant to be meeting the NAAQS and the area near the Harrington plant as “unclassifiable.” The area near the Harrington plant is to be monitored for three years and a final designation is expected to be made by December 2020.

If an area is designated nonattainment in 2020, the respective states will need to evaluate all SO₂ sources in the area. The state would then submit an implementation plan, which would be due by 2022, designed to achieve the NAAQS by 2025. The TCEQ could require additional SO₂ controls at Harrington as part of such a plan. SPS cannot evaluate the impacts until the designation of nonattainment areas is made and any required state plans are developed. SPS believes that, should 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.

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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.

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, 2016			Year Ended Dec. 31, 2015
Borrowing limit	$	100		$	100
Amount outstanding at period end	100			—
Average amount outstanding	50			21
Maximum amount outstanding	100			100
Weighted average interest rate, computed on a daily basis	0.64		%	0.40		%
Weighted average interest rate at period end	0.62			N/A

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, 2016			Year Ended Dec. 31, 2015
Borrowing limit	$	400		$	400
Amount outstanding at period end	25			15
Average amount outstanding	71			100
Maximum amount outstanding	140			246
Weighted average interest rate, computed on a daily basis	0.67		%	0.46		%
Weighted average interest rate at period end	0.65			0.60

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, 2016 and Dec. 31, 2015, there were $7 million of letters of credit outstanding under the credit facility. The contract amounts of these letters of credit approximate their fair value and are subject to fees.

Credit Facility — In order to use its commercial paper program, SPS must have a 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 credit facility capacity. 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, 2016, SPS had the following committed credit facility available (in millions of dollars):

Credit Facility (a)		Drawn(b)		Available
$	400	$	32	$	368

^(a)  This credit facility expires in June 2021.

^(b)  Includes outstanding commercial paper and letters of credit.

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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, 2016 and Dec. 31, 2015.

Amended Credit Agreements - In June 2016, SPS entered into an amended five-year credit agreement with a syndicate of banks. The total borrowing limit under the amended credit agreement remained at $400 million. The amended credit agreement has substantially the same terms and conditions as the prior credit agreement with the following exceptions:

• The maturity extended from October 2019 to June 2021.

• The Eurodollar borrowing margins on these lines of credit were reduced to a range of 75 to 150 basis points per year, from a range of 87.5 to 175 basis points per year, based upon applicable long-term credit ratings.

• The commitment fees, calculated on the unused portion of the lines of credit, were reduced to a range of 6 to 22.5 basis points per year, from a range of 7.5 to 27.5 basis points per year, also based on applicable long-term credit ratings.

SPS has the right to request an extension of the revolving credit facility termination date for two additional one-year periods, subject to majority bank group approval.

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 prices.

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, referred to as financial transmission rights (FTRs). FTRs purchased from a regional transmission organization (RTO) are financial instruments that entitle or obligate the holder to monthly revenues or charges based on transmission congestion across a given transmission path. The value of an FTR is derived from, and designed to offset, the cost of energy congestion, which is caused by transmission load and transmission constraints. Congestion is also influenced by the operating schedules of power plants and the consumption of electricity. Unplanned plant outages, scheduled plant maintenance, changes in the costs of fuels used in generation, weather and changes in demand for electricity can each impact the operating schedules of the power plants 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.

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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 fair value measurements for FTRs have been assigned a Level 3. Monthly settlements for non-trading FTRs 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, 2016, accumulated other comprehensive losses related to interest rate derivatives included $0.1 million of net losses expected to be reclassified into earnings during the next 12 months as the related hedged interest rate transactions impact earnings, including forecasted amounts for unsettled hedges, as applicable.

Wholesale and Commodity Trading Risk — SPS conducts various wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy and energy-related instruments. SPS’ risk management policy allows management to conduct these activities within guidelines and limitations as approved by its risk management committee.

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, 2016 and Dec. 31, 2015:

(Amounts in Thousands) (a)	June 30, 2016	Dec. 31, 2015
Megawatt hours of electricity	6,255	6,192

^(a)  Amounts are not reflective of net positions in the underlying commodities.

Impact of Derivative Activities on Income and Accumulated Other Comprehensive Loss — Pre-tax losses related to interest rate derivatives reclassified from accumulated other comprehensive loss into earnings were $0.1 million for the three and six months ended June 30, 2016 and 2015.

During the three and six months ended June 30, 2016, changes in the fair value of FTRs resulted in pre-tax net gains of $0.5 million and $1.8 million, respectively and were recognized as regulatory assets and liabilities. For 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. The classification as a regulatory asset or liability is based on expected recovery of FTR settlements through fuel and purchased energy cost recovery mechanisms.

FTR settlement losses of $3.1 million and $3.2 million were recognized for the three and six months ended June 30, 2016, recorded to electric fuel and purchased power. For the three and six months ended June 30, 2015, FTR settlement gains of $1.7 million and $1.6 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, 2016 and 2015. Therefore, no gains or losses from fair value hedges or related hedged transactions were recognized for these periods.

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Consideration of Credit Risk and Concentrations — SPS 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. 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 , 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 are contracts with counterparties to its wholesale, trading and non-trading commodity and transmission activities. At June 30, 2016, eight of the most significant counterparties, comprising $46.5 million or 53 percent of this credit exposure, were not rated by Standard & Poor’s Ratings Services, Moody’s Investor Services or Fitch Ratings, but based on SPS’ internal analysis, had credit quality consistent with investment grade. Another of these significant counterparties, comprising $0.5 million or 1 percent of this credit exposure, had credit quality less than investment grade, based on ratings from external analysis. 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, 2016:

	June 30, 2016
	Fair Value						Fair Value Total		Counterparty Netting (b)
(Thousands of Dollars)	Level 1		Level 2		Level 3							Total
Current derivative assets
Other derivative instruments:
Electric commodity	$	—	$	—	$	4,021	$	4,021	$	(2,951	)	$	1,070
Total current derivative assets	$	—	$	—	$	4,021	$	4,021	$	(2,951	)	1,070
PPAs (a)												5,526
Current derivative instruments												$	6,596
Noncurrent derivative assets
PPAs (a)												$	23,692
Noncurrent derivative instruments												$	23,692
Current derivative liabilities
Other derivative instruments:
Electric commodity	$	—	$	—	$	2,951	$	2,951	$	(2,951	)	$	—
Total current derivative liabilities	$	—	$	—	$	2,951	$	2,951	$	(2,951	)	—
PPAs (a)												3,565
Current derivative instruments												$	3,565
Noncurrent derivative liabilities
PPAs (a)												$	25,296
Noncurrent derivative instruments												$	25,296

^(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, 2016. At June 30, 2016, derivative assets and liabilities include no obligations to return cash collateral or rights to reclaim cash collateral. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.

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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, 2015:

	Dec. 31, 2015
	Fair Value						Fair Value Total		Counterparty Netting (b)
(Thousands of Dollars)	Level 1		Level 2		Level 3							Total
Current derivative assets
Other derivative instruments:
Electric commodity	$	—	$	—	$	8,980	$	8,980	$	(3,920	)	$	5,060
Total current derivative assets	$	—	$	—	$	8,980	$	8,980	$	(3,920	)	5,060
PPAs (a)												7,892
Current derivative instruments												$	12,952
Noncurrent derivative assets
PPAs (a)												$	25,272
Noncurrent derivative instruments												$	25,272
Current derivative liabilities
Other derivative instruments:
Electric commodity	$	—	$	—	$	3,920	$	3,920	$	(3,920	)	$	—
Total current derivative liabilities	$	—	$	—	$	3,920	$	3,920	$	(3,920	)	—
PPAs (a)												3,565
Current derivative instruments												$	3,565
Noncurrent derivative liabilities
PPAs (a)												$	27,078
Noncurrent derivative instruments												$	27,078

^(a)  In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, SPS began recording several long-term PPAs at fair value due to accounting requirements related to underlying price adjustments. As these purchases are recovered through normal regulatory recovery mechanisms in the respective jurisdictions, the changes in fair value for these contracts were offset by regulatory assets and liabilities. During 2006, SPS qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.

^(b)  SPS nets derivative instruments and related collateral in its balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Dec. 31, 2015. At Dec. 31, 2015, derivative assets and liabilities include no obligations to return cash collateral or rights to reclaim cash collateral. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.

The following table presents the changes in Level 3 commodity derivatives for the three and six months ended June 30, 2016 and 2015:

	Three Months Ended June 30
(Thousands of Dollars)	2016			2015
Balance at April 1	$	1,730		$	6,457
Purchases	1,956			17,284
Settlements	(7,130		)	(10,022		)
Net transactions recorded during the period:
Gains (losses) recognized as regulatory assets and liabilities	4,514			(2,256		)
Balance at June 30	$	1,070		$	11,463

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	Six Months Ended June 30
(Thousands of Dollars)	2016			2015
Balance at Jan. 1	$	5,060		$	15,884
Purchases	3,800			22,213
Settlements	(14,122		)	(18,400		)
Net transactions recorded during the period:
Gains (losses) recognized as regulatory assets and liabilities	6,332			(8,234		)
Balance at June 30	$	1,070		$	11,463

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, 2016 and 2015.

Fair Value of Long-Term Debt

As of June 30, 2016 and Dec. 31, 2015, other financial instruments for which the carrying amount did not equal fair value were as follows:

	June 30, 2016				Dec. 31, 2015
(Thousands of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion (a)	$	1,539,177	$	1,775,895	$	1,538,522	$	1,678,673

^(a)  Amounts reflect the classification of debt issuance costs as a deduction from the carrying amount of the related debt. See Note 2, Accounting Pronouncements for more information on the adoption of ASU 2015-03.

The fair value of SPS’ long-term debt is estimated based on recent trades and observable spreads from benchmark interest rates for similar securities. The fair value estimates are based on information available to management as of June 30, 2016 and Dec. 31, 2015, and given the observability of the inputs to these estimates, the fair values presented for long-term debt have been assigned a Level 2.

9. Other Income, Net

Other income, net consisted of the following:

	Three Months Ended    June 30				Six Months Ended   June 30
(Thousands of Dollars)	2016		2015		2016		2015
Interest income	$	94	$	13	$	179	$	45
Other nonoperating income	298		65		247		110
Insurance policy income (expense)	—		78		—		(55		)
Other income, net	$	392	$	156	$	426	$	100

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10. Benefit Plans and Other Postretirement Benefits

Components of Net Periodic Benefit Cost (Credit)

	Three Months Ended    June 30
	2016			2015			2016			2015
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Service cost	$	2,440		$	2,751		$	194		$	238
Interest cost	5,315			5,046			455			437
Expected return on plan assets	(6,901		)	(7,152		)	(594		)	(635		)
Amortization of prior service cost (credit)	—			10			(100		)	(100		)
Amortization of net loss (gain)	2,997			3,772			(146		)	(160		)
Net periodic benefit cost (credit)	3,851			4,427			(191		)	(220		)
Credits recognized due to the effects of regulation	638			686			—			—
Net benefit cost (credit) recognized for financial reporting	$	4,489		$	5,113		$	(191	)	$	(220	)

	Six Months Ended   June 30
	2016			2015			2016			2015
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Service cost	$	4,880		$	5,503		$	388		$	477
Interest cost	10,630			10,092			910			873
Expected return on plan assets	(13,802		)	(14,305		)	(1,188		)	(1,270		)
Amortization of prior service cost (credit)	—			20			(200		)	(200		)
Amortization of net loss (gain)	5,994			7,544			(292		)	(320		)
Net periodic benefit cost (credit)	7,702			8,854			(382		)	(440		)
Credits recognized due to the effects of regulation	716			1,399			—			—
Net benefit cost (credit) recognized for financial reporting	$	8,418		$	10,253		$	(382	)	$	(440	)

In January 2016, contributions of $125.0 million were made across four of Xcel Energy’s pension plans, of which $18.0 million was attributable to SPS. Xcel Energy does not expect additional pension contributions during 2016.

11. Other Comprehensive Income

Changes in accumulated other comprehensive loss, net of tax, for the three and six months ended June 30, 2016 and 2015 were as follows:

	Three Months Ended June 30, 2016
(Thousands of Dollars)	Gains and Losses on Cash Flow Hedges			Defined Benefit and Postretirement Items			Total
Accumulated other comprehensive loss at April 1	$	(775	)	$	(452	)	$	(1,227	)
Other comprehensive loss before reclassifications	—			11			11
Losses reclassified from net accumulated other comprehensive loss	43			—			43
Net current period other comprehensive income	43			11			54
Accumulated other comprehensive loss at June 30	$	(732	)	$	(441	)	$	(1,173	)

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

	Six Months Ended June 30, 2016
(Thousands of Dollars)	Gains and Losses on Cash Flow Hedges			Defined Benefit and Postretirement Items			Total
Accumulated other comprehensive loss at Jan. 1	$	(817	)	$	(464	)	$	(1,281	)
Other comprehensive loss before reclassifications	—			23			23
Losses reclassified from net accumulated other comprehensive loss	85			—			85
Net current period other comprehensive income	85			23			108
Accumulated other comprehensive loss at June 30	$	(732	)	$	(441	)	$	(1,173	)

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

Reclassifications from accumulated other comprehensive loss for the three and six months ended June 30, 2016 and 2015 were as follows:

	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Three Months Ended June 30, 2016				Three Months Ended June 30, 2015
Losses on cash flow hedges:
Interest rate derivatives	$	67		(a)	$	67		(a)
Total, pre-tax	67				67
Tax benefit	(24		)		(24		)
Total amounts reclassified, net of tax	$	43			$	43

	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Six Months Ended June 30, 2016				Six Months Ended June 30, 2015
Losses on cash flow hedges:
Interest rate derivatives	$	134		(a)	$	133		(a)
Total, pre-tax	134				133
Tax benefit	(49		)		(48		)
Total amounts reclassified, net of tax	$	85			$	85

^(a)  Included in interest charges.

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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 herein, 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 expressly disclaim any obligation to update any forward-looking information. The following factors, in addition to those discussed elsewhere in this Quarterly Report on Form 10-Q and in other securities filings (including SPS’ Annual Report on Form 10-K for the fiscal year ended Dec. 31, 2015 and Quarterly Report on Form 10-Q for the quarter ended March 31, 2016), could cause actual results to differ materially from management expectations as suggested by such forward-looking information: 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 slow down 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 and natural gas markets; costs and other effects of legal and administrative proceedings, settlements, investigations and claims; financial or regulatory accounting policies imposed by regulatory bodies; outcomes of regulatory proceedings; availability of cost of capital; and employee work force factors.

Results of Operations

SPS’ net income was approximately $54.7 million for the six months endedJune 30, 2016, compared with net income of approximately $42.8 million for the same period in 2015. Higher electric margin and lower O&M expenses were partially offset by additional depreciation.

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)	2016			2015
Electric revenues	$	831		$	847
Electric fuel and purchased power	(460		)	(489		)
Electric margin	$	371		$	358

21

The following tables summarize the components of the changes in electric revenues and electric margin for the six months endedJune 30, 2016:

Electric Revenues

(Millions of Dollars)	2016 vs. 2015
Fuel and purchased power cost recovery	$	(24	)
Trading	(13		)
Retail rate decrease (Texas)	(4		)
Transmission revenue	20
Other, net	5
Total decrease in electric revenues	$	(16	)

Electric Margin

(Millions of Dollars)	2016 vs. 2015
Transmission revenue, net of costs	$	7
Fuel handling	6
Retail rate decrease (Texas)	(4		)
Other, net	4
Total increase in electric margin	$	13

Non-Fuel Operating Expense and Other Items

O&M Expenses — O&M expenses decreased $17.0 million, or 11.5 percent, for the six months endedJune 30, 2016, compared with the same period in 2015. The decrease was mainly due to the timing and scope of plant outages and lower employee benefit costs.

Depreciation and Amortization — Depreciation and amortization increased $8.7 million, or 12.1 percent, for the six months endedJune 30, 2016, compared with the same period in 2015. The increase is primarily due to new capital investments.

Taxes (Other Than Income Taxes) — Taxes (other than income taxes) increased $2.4 million, or 8.3 percent, for the six months endedJune 30, 2016, compared with the same period in 2015. The increase is primarily due to higher property taxes.

Allowance for funds used during construction (AFUDC) —AFUDC increased $1.7 million, for the six months endedJune 30, 2016, compared with the same period in 2015. The increase is primarily due to the increase in construction projects.

Interest Charges — Interest charges increased $2.0 million, or 4.9 percent, for the six months endedJune 30, 2016, compared with the same period in 2015. The increase is primarily due to higher long-term debt levels, partially offset by refinancings at lower interest rates.

Income Taxes — Income tax expense increased $7.2 million, for the six months endedJune 30, 2016, compared with the same period in 2015. The increase in income tax expense is primarily due to higher pretax earnings in 2016. The ETR was 36.2 percent for the six months endedJune 30, 2016, compared with 35.8 percent for the same period in 2015.

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, 2015, appropriately represent, in all material respects, the current status of public utility regulation, and are incorporated herein by reference.

TUCO Substation to Yoakum County Substation to Hobbs Plant Substation 345 Kilovolt (KV) Transmission Line— In June 2015, SPS filed a certificate of convenience and necessity (CCN) with the PUCT for the Yoakum County to Texas/New Mexico State line portion of this 345 KV line project. The PUCT approved this CCN in March 2016. CCNs for the TUCO to Yoakum County substation segment were filed in June 2016. CCNs for the Texas/New Mexico state line to Hobbs Plant segment are planned to be filed in the second half of 2016. The estimated project cost is $242 million. This line is scheduled to be in service in 2019.

22

Hobbs Plant Substation to China Draw Substation 345 KV Transmission Line — In May 2016, SPS filed a CCN with the NMPRC for the Hobbs Plant to China Draw transmission line. The estimated project cost is approximately $163 million. The line is anticipated to be in service in 2018.

Wholesale Customer Participation in Electric Reliability Council of Texas (ERCOT) — In March 2016, the PUCT Staff requested comments on Lubbock Power & Light’s (LP&L’s) proposal to transition a portion of its load (approximately 430 MW on a peak basis) to the ERCOT in June 2019. LP&L’s proposal would result in an approximate seven percent reduction of load in SPS, or a loss of approximately $18 million in wholesale transmission revenue based on 2015 revenue requirements.  The remaining portion of LP&L’s load (approximately 170 MW) would continue to be served by SPS. Should LP&L join ERCOT, costs to SPS’ remaining customers would increase as SPS’ transmission revenue requirement would be spread across a smaller base of customers.  SPS intends to participate in the PUCT’s proceeding to protect its customers’ interests. LP&L has stated that it intends to file an application with the PUCT for a CCN for approval of the transfer by late 2016.

The PUCT has indicated there will be a two-step process regarding LP&L’s possible transfer to ERCOT. The first step will be a proceeding to determine whether the proposed transfer is in the public interest and to consider certain protections for non-LP&L customers who would be affected by LP&L’s transfer. If the PUCT determines the transfer is in the public interest, the second step will be for LP&L to file a CCN application for transmission facilities to connect with ERCOT. The PUCT has stated it intends to discuss, and possibly decide, issues regarding procedures, timing, scope of proceedings and types of analyses in August 2016.

In May 2016, SPS submitted a filing to the FERC seeking approval to impose an Interconnection Switching Fee (exit fee) associated with LP&L’s proposal.  In June 2016, LP&L and Golden Spread Electric Cooperative, Inc. (Golden Spread) protested SPS’ filing. LP&L argued that SPS has no legal authority to impose a charge and LP&L’s departure would reduce certain costs to SPS and asked the FERC to reject the filing. Golden Spread asked FERC to clarify that if the exit fee is not approved, remaining wholesale transmission customers could challenge future recovery of SPS’ costs. Additionally, the PUCT asked FERC to hold the filing in abeyance pending the outcome of the PUCT proceedings evaluating the LP&L proposal. SPS requested FERC to act on the matter by mid-September 2016.

Summary of Recent Federal Regulatory Developments

The Pipeline and Hazardous Materials Safety Administration

Pipeline Safety Act — The Pipeline Safety, Regulatory Certainty, and Job Creation Act (Pipeline Safety Act) requires additional verification of pipeline infrastructure records by pipeline owners and operators to confirm the maximum allowable operating pressure of lines located in high consequence areas or more-densely populated areas.  The DOT Pipeline and Hazardous Materials Safety Administration (PHMSA) recently released proposed rules that address this verification requirement along with a number of other significant changes to gas transmission regulations.  These changes include requirements around use of automatic or remote-controlled shut-off valves; testing of certain previously untested transmission lines; and expanding integrity management requirements. The Pipeline Safety Act also includes a maximum penalty for violating pipeline safety rules of $2 million per day for related violations. 

SPS recently commented on the proposed rules and continues to analyze the proposed rule changes as they relate to costs, current operations and financial results.  PHMSA has indicated that they intend for the rules to go into effect in late 2016. 

SPS has been taking actions that were intended to comply with the Pipeline Safety Act and any related PHMSA regulations as they become effective.  While SPS cannot predict the ultimate impact Pipeline Safety Act will have on its costs, operations or financial results, it is taking actions that are intended to comply with the Pipeline Safety Act and any related PHMSA regulations as they become effective.

FERC

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, 2015 and Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2016. In addition to the matters discussed below, see Note 5 to the financial statements for a discussion of other regulatory matters.

23

FERC Order, New ROE Policy — The FERC has 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 litigated ROE complaint proceedings until later in 2016 or 2017.

SPS Asset Transfer to Xcel Energy Southwest Transmission Company, LLC (XEST) — In 2015 through early 2016, SPS submitted filings to the FERC, PUCT, NMPRC and Kansas Corporation Commission (KCC) seeking approval to transfer ownership of SPS’ 345 KV transmission assets in Kansas and Oklahoma to XEST at net book value of approximately $103 million.

In June 2016, SPS and XEST made filings to withdraw the pending PUCT, NMPRC, KCC, and FERC applications due to the relatively slow pace of Order 1000 competitive transmission development projects in the SPP. All withdrawal requests have been granted, and the matters are now closed.

Formula Rate Treatment of Accumulated Deferred Income Taxes (ADIT) — In 2015, SPS filed changes to its transmission formula rates to modify the treatment of ADIT to comply with IRS guidance regarding how ADIT must be reflected in formula rates using future test years and a true-up. The filings are intended to ensure that SPS is in compliance with IRS rules and may continue to use accelerated tax depreciation.

Golden Spread protested the proposed changes to the SPS transmission formula rate. In April 2016, FERC accepted the SPS formula rate changes, subject to a compliance filing. SPS submitted the compliance filing in May 2016.

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 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, 2016, 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

Effective January 2016, SPS implemented the general ledger modules of a new enterprise resource planning (ERP) system to improve certain financial and related transaction processes. During 2016 and 2017, SPS will continue implementing additional modules and expects to begin conversion of existing work management systems to this new ERP system. In connection with this ongoing implementation, SPS has updated and will continue updating its internal control over financial reporting, as necessary, to accommodate modifications to its business processes and accounting procedures. SPS does not expect the implementation of the additional modules to materially affect its internal control over financial reporting.

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

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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 a 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, 2015, 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.

Item 6 — EXHIBITS

*	Indicates incorporation by reference
+	Executive Compensation Arrangements and Benefit Plans Covering Executive Officers and Directors

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)).
10.01*+	Fifth Amendment dated May 3, 2016 to the Xcel Energy Senior Executive Severance and Change-in-Control Policy (Exhibit 10.01 to Form 10-Q of Xcel Energy dated Aug. 4, 2016 (file no. 001-03034)).
10.02*	Second Amended and Restated Credit Agreement, dated as of June 20, 2016 among SPS, as Borrower, the several lenders from time to time parties thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, Bank of America, N.A. and Barclays Bank Plc, as Syndication Agents, and Wells Fargo Bank, National Association and The Bank of Tokyo-Mitsubishi UFJ, Ltd., as Documentation Agents. (Exhibit 99.04 to Form 8-K of Xcel Energy, dated June 20, 2016 (file no. 001-03034)).
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, 2016 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.

25

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. 4, 2016	By:	/s/ JEFFREY S. SAVAGE
		Jeffrey S. Savage
		Senior Vice President, Controller
		(Principal Accounting Officer)
		/s/ ROBERT C. FRENZEL
		Robert C. Frenzel
		Executive Vice President, Chief Financial Officer and Director
		(Principal Financial Officer)

26

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. 4, 2016

/s/ BEN FOWKE

Ben Fowke

Chairman, Chief Executive Officer and Director

(Principal Executive Officer)

1

EX-31.02

Exhibit 31.02

CERTIFICATION

I, Robert C. Frenzel, 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. 4, 2016

/s/ ROBERT C. FRENZEL

Robert C. Frenzel

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, 2016, 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. 4, 2016

/s/ BEN FOWKE

Ben Fowke

Chairman, Chief Executive Officer and Director

(Principal Executive Officer)

/s/ ROBERT C. FRENZEL

Robert C. Frenzel

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, 2015, 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

Document and Entity Information - shares	6 Months Ended
	Jun. 30, 2016	Aug. 04, 2016
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
Entity Common Stock, Shares Outstanding		100
Document Fiscal Year Focus	2016
Document Fiscal Period Focus	Q2
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Jun. 30, 2016

XML

STATEMENTS OF INCOME (UNAUDITED) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Income Statement [Abstract]
Operating revenues	$ 440,445	$ 422,985	$ 831,284	$ 846,814
Operating expenses
Electric fuel and purchased power	246,547	243,026	459,950	488,825
Operating and maintenance expenses	66,588	73,827	130,711	147,724
Demand side management program expenses	3,239	2,760	6,616	6,429
Depreciation and amortization	40,893	36,750	81,224	72,489
Taxes (other than income taxes)	14,792	13,490	30,828	28,456
Total operating expenses	372,059	369,853	709,329	743,923
Operating income	68,386	53,132	121,955	102,891
Other income, net	392	156	426	100
Allowance for funds used during construction — equity	2,379	1,788	4,716	3,493
Interest charges and financing costs
Interest charges — includes other financing costs of $813, $771, $1,633 and $1,544, respectively	22,075	21,074	44,007	41,958
Public Utilities, Allowance For Funds Used During Construction, Capitalized Cost Of Debt	(1,397)	(1,137)	(2,724)	(2,198)
Total interest charges and financing costs	20,678	19,937	41,283	39,760
Income before income taxes	50,479	35,139	85,814	66,724
Income taxes	18,268	12,563	31,080	23,901
Net income	$ 32,211	$ 22,576	$ 54,734	$ 42,823

XML

STATEMENTS OF INCOME (UNAUDITED) (Parenthetical) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Interest charges and financing costs
Other financing costs	$ 813	$ 771	$ 1,633	$ 1,544

XML

STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Comprehensive income:
Net income	$ 32,211	$ 22,576	$ 54,734	$ 42,823
Pension and retiree medical benefits:
Net Amortization of losses included in net periodic benefit cost, net of tax of $6, $0, $13 and $0, respectively	11	0	23	0
Derivative instruments:
Reclassification of losses to net income, net of tax of $24, $24, $49 and $48, respectively	43	43	85	85
Other comprehensive income	54	43	108	85
Comprehensive income	$ 32,265	$ 22,619	$ 54,842	$ 42,908

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STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED) (Parenthetical) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Derivative instruments:
Reclassification of losses to net income, tax	$ 24	$ 24	$ 49	$ 48
Other Comprehensive (Income) Loss, Amortization Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Prior Service Cost (Credit), Tax	$ 6	$ 0	$ 13	$ 0

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STATEMENTS OF CASH FLOWS (UNAUDITED) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015
Operating activities
Net income	$ 54,734	$ 42,823
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	81,600	73,628
Demand side management program amortization	837	837
Deferred income taxes	53,217	11,866
Amortization of investment tax credits	(106)	(170)
Allowance for equity funds used during construction	(4,716)	(3,493)
Net derivative losses	134	133
Changes in operating assets and liabilities:
Accounts receivable	(12,997)	(19,478)
Accrued unbilled revenues	(25,690)	10,927
Inventories	5,889	10,776
Prepayments and other	30,189	(21,378)
Accounts payable	9,888	(10,210)
Net regulatory assets and liabilities	(3,216)	41,291
Other current liabilities	(4,862)	13,510
Pension and other employee benefit obligations	(16,357)	(10,435)
Change in other noncurrent assets	(373)	607
Change in other noncurrent liabilities	2,693	606
Net cash provided by operating activities	170,864	141,840
Investing activities
Utility capital/construction expenditures	(263,653)	(280,615)
Proceeds from insurance recoveries	987	0
Allowance for equity funds used during construction	4,716	3,493
Investments in utility money pool arrangement	0	(9,000)
Repayments from utility money pool arrangement	0	9,000
Other	(1,174)	0
Net cash used in investing activities	(259,124)	(277,122)
Financing activities
Proceeds from short-term borrowings, net	10,000	172,000
Repayment of long-term debt	0	(85)
Borrowings under utility money pool arrangement	391,000	163,700
Repayments under utility money pool arrangement	(291,000)	(179,700)
Capital contributions from parent	16,225	34,535
Dividends paid to parent	(38,182)	(53,167)
Net cash provided by financing activities	88,043	137,283
Net change in cash and cash equivalents	(217)	2,001
Cash and cash equivalents at beginning of period	834	596
Cash and cash equivalents at end of period	617	2,597
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	(39,960)	(38,527)
Cash received (paid) for income taxes, net	41,170	(36,992)
Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable	$ 30,172	$ 26,513

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BALANCE SHEETS (UNAUDITED) - USD ($) $ in Thousands	Jun. 30, 2016	Dec. 31, 2015
Current assets
Cash and cash equivalents	$ 617	$ 834
Accounts receivable, net	84,008	71,166
Accounts receivable from affiliates	1,234	1,079
Accrued unbilled revenues	129,471	103,781
Inventories	31,657	37,546
Regulatory assets	30,656	31,541
Derivative instruments	6,596	12,952
Deferred income taxes	39,747	35,686
Prepaid taxes	16,573	35,666
Prepayments and other	8,436	20,520
Total current assets	348,995	350,771
Property, plant and equipment, net	4,520,672	4,348,823
Other assets
Regulatory assets	304,345	301,814
Derivative instruments	23,692	25,272
Other	4,997	3,449
Total other assets	333,034	330,535
Total assets	5,202,701	5,030,129
Current liabilities
Current portion of long-term debt	200,000	200,000
Short-term debt	25,000	15,000
Borrowings Payable Under Utility Money Pool Arrangement	100,000	0
Accounts payable	155,556	146,794
Accounts payable to affiliates	13,073	29,135
Regulatory liabilities	84,499	98,305
Taxes accrued	31,413	33,374
Accrued interest	17,666	17,781
Dividends payable	19,388	12,538
Derivative instruments	3,565	3,565
Other	31,262	35,654
Total current liabilities	681,422	592,146
Deferred credits and other liabilities
Deferred income taxes	953,522	896,430
Regulatory liabilities	235,479	229,584
Asset retirement obligations	27,949	27,233
Derivative instruments	25,296	27,078
Pension and employee benefit obligations	76,825	93,346
Other	20,272	17,841
Total deferred credits and other liabilities	1,339,343	1,291,512
Commitments and contingencies
Capitalization
Long-term debt	1,339,177	1,338,522
Common stock — 200 shares authorized of $1.00 par value; 100 shares outstanding at June 30, 2016 and Dec. 31, 2015, respectively	0	0
Additional paid in capital	1,396,223	1,371,223
Retained earnings	447,709	438,007
Accumulated other comprehensive loss	(1,173)	(1,281)
Total common stockholder’s equity	1,842,759	1,807,949
Total liabilities and equity	$ 5,202,701	$ 5,030,129

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BALANCE SHEETS (UNAUDITED) (Parenthetical) - $ / shares	Jun. 30, 2016	Dec. 31, 2015
Capitalization, Long-term Debt and Equity [Abstract]
Common stock, shares authorized (in shares)	200	200
Common stock, par value (in dollars per share)	$ 1	$ 1
Common stock, shares outstanding (in shares)	100	100

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Management's Opinion

6 Months Ended

Jun. 30, 2016

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, 2016, and Dec. 31, 2015; the results of its operations, including the components of net income and comprehensive income, for the three and six months ended June 30, 2016 and 2015; and its cash flows for the six months endedJune 30, 2016 and 2015. All adjustments are of a normal, recurring nature, except as otherwise disclosed. Management has also evaluated the impact of events occurring after June 30, 2016 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, 2015 balance sheet information has been derived from the audited 2015 financial statements included in the SPS Annual Report on Form 10-K for the year ended Dec. 31, 2015. 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, 2015, filed with the SEC on Feb. 22, 2016. 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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Summary of Significant Accounting Policies

6 Months Ended

Jun. 30, 2016

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, 2015, appropriately represent, in all material respects, the current status of accounting policies and are incorporated herein by reference.

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Accounting Pronouncements

6 Months Ended

Jun. 30, 2016

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. 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.

Presentation of Deferred Taxes — In November 2015, the FASB issued Balance Sheet Classification of Deferred Taxes, Topic 740 (ASU No 2015-17), which eliminates the requirement to present deferred tax assets and liabilities as current and noncurrent on the balance sheet based on the classification of the related asset or liability, and instead requires classification of all deferred tax assets and liabilities as noncurrent. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, 2016, and early adoption is permitted. Other than the prescribed classification of all deferred tax assets and liabilities as noncurrent, SPS does not expect the implementation of ASU 2015-17 to have a material impact on its financial statements.

Classification and Measurement of Financial Instruments — In January 2016, the FASB issued Recognition and Measurement of Financial Assets and Financial Liabilities, Subtopic 825-10 (ASU No. 2016-01), which among other changes in accounting and disclosure requirements, replaces the cost method of accounting for non-marketable equity securities with a model for recognizing impairments and observable price changes, and also eliminates the available-for-sale classification for marketable equity securities. Under the new guidance, other than when the consolidation or equity method of accounting is utilized, changes in the fair value of equity securities are to be recognized in earnings. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, 2017. SPS is currently evaluating the impact of adopting ASU 2016-01 on its financial statements.

Leases — In February 2016, the FASB issued Leases, Topic 842 (ASU No. 2016-02), which, for lessees, requires balance sheet recognition of right-of-use assets and lease liabilities for all leases. Additionally, for leases that qualify as finance leases, the guidance requires expense recognition consisting of amortization of the right-of-use asset as well as interest on the related lease liability using the effective interest method. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, 2018, and early adoption is permitted. SPS is currently evaluating the impact of adopting ASU 2016-02 on its financial statements.

Stock Compensation — In March 2016, the FASB issued Improvements to Employee Share-Based Payment Accounting, Topic 718 (ASU 2016-09), which amends existing guidance to simplify several aspects of accounting and presentation for share-based payment transactions, including the accounting for income taxes and forfeitures, as well as presentation in the statement of cash flows. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, 2016, and early adoption is permitted. SPS does not expect the implementation of ASU 2016-09 to have a material impact on its financial statements.

Recently Adopted

Consolidation— In February 2015, the FASB issued Amendments to the Consolidation Analysis, Topic 810 (ASU No. 2015-02), which reduces the number of consolidation models and amends certain consolidation principles related to variable interest entities. SPS implemented the guidance on Jan. 1, 2016, and the implementation did not have a significant impact on its financial statements.

Presentation of Debt Issuance Costs— In April 2015, the FASB issued Simplifying the Presentation of Debt Issuance Costs, Subtopic 835-30 (ASU No. 2015-03), which requires the presentation of debt issuance costs on the balance sheet as a deduction from the carrying amount of the related debt, instead of presentation as an asset. SPS implemented the new guidance as required on Jan. 1, 2016, and as a result, $11.8 million of deferred debt issuance costs were presented as a deduction from the carrying amount of long-term debt on the balance sheet as of March 31, 2016, and $12.1 million of such deferred costs were retrospectively reclassified from other non-current assets to long-term debt on the balance sheet as of Dec. 31, 2015.

Fair Value Measurement— In May 2015, the FASB issued Disclosures for Investments in Certain Entities that Calculate Net Asset Value per Share (or Its Equivalent), Topic 820 (ASU No. 2015-07), which eliminates the requirement to categorize fair value measurements using a net asset value methodology in the fair value hierarchy. SPS implemented the guidance on Jan. 1, 2016, and the implementation did not have a material impact on its financial statements.

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Selected Balance Sheet Data

6 Months Ended

Jun. 30, 2016

Balance Sheet Related Disclosures [Abstract]

Selected Balance Sheet Data

Selected Balance Sheet Data

(Thousands of Dollars)	June 30, 2016			Dec. 31, 2015
Accounts receivable, net
Accounts receivable	$	89,872		$	77,054
Less allowance for bad debts	(5,864		)	(5,888		)
	$	84,008		$	71,166

(Thousands of Dollars)	June 30, 2016		Dec. 31, 2015
Inventories
Materials and supplies	$	25,525	$	24,888
Fuel	6,132		12,658
	$	31,657	$	37,546

(Thousands of Dollars)	June 30, 2016			Dec. 31, 2015
Property, plant and equipment, net
Electric plant	$	6,119,713		$	5,933,764
Construction work in progress	277,974			236,697
Total property, plant and equipment	6,397,687			6,170,461
Less accumulated depreciation	(1,877,015		)	(1,821,638		)
	$	4,520,672		$	4,348,823

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Income Taxes

6 Months Ended

Jun. 30, 2016

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, 2015 appropriately represents, in all material respects, the current status of other income tax matters, and are incorporated herein by reference.

Federal Audit — SPS is a member of the Xcel Energy affiliated group that files a consolidated federal income tax return. In 2012, the Internal Revenue Service (IRS) commenced an examination of tax years 2010 and 2011, including the 2009 carryback claim. As of June 30, 2016, the IRS had proposed an adjustment to the federal tax loss carryback claims that would result in $14 million of income tax expense for the 2009 through 2011 and 2013 claims, the recently filed 2014 claim, and the anticipated claim for 2015. SPS is not expected to accrue any income tax expense related to this adjustment. In the fourth quarter of 2015, the IRS forwarded the issue to the Office of Appeals (Appeals). During the second quarter of 2016 the IRS audit team presented their case to Appeals; however, the outcome and timing of a resolution are uncertain. The statute of limitations applicable to Xcel Energy’s 2009 through 2011 federal income tax returns expires in December 2016 following an extension to allow additional time for the Appeals process. In the third quarter of 2015, the IRS commenced an examination of tax years 2012 and 2013. As of June 30, 2016, the IRS had not proposed any material adjustments to tax years 2012 and 2013.

State Audits — SPS is a member of the Xcel Energy affiliated group that files consolidated state income tax returns. As of June 30, 2016, SPS’ earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations is 2009. In February 2016, Texas began an audit of years 2009 and 2010. As of June 30, 2016, Texas had not proposed any adjustments, and there were no other state income tax audits in progress.

Unrecognized Tax Benefits — The unrecognized tax benefit balance includes permanent tax positions, which if recognized would affect the annual 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, 2016		Dec. 31, 2015
Unrecognized tax benefit — Permanent tax positions	$	2.7	$	2.6
Unrecognized tax benefit — Temporary tax positions	21.9		22.1
Total unrecognized tax benefit	$	24.6	$	24.7

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, 2016			Dec. 31, 2015
NOL and tax credit carryforwards	$	(5.2	)	$	(5.0	)

It is reasonably possible that SPS’ amount of unrecognized tax benefits could significantly change in the next 12 months as the IRS Appeals and audit progress, the Texas audit progresses, and other state audits resume. As the IRS Appeals, IRS audit, and Texas audit progress, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $7 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, 2016 and Dec. 31, 2015 were not material. No amounts were accrued for penalties related to unrecognized tax benefits as of June 30, 2016 or Dec. 31, 2015.

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Rate Matters

6 Months Ended

Jun. 30, 2016

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, 2015, appropriately represent, in all material respects, the current status of other rate matters, and are incorporated herein by reference.

Pending Regulatory Proceedings — Public Utility Commission of Texas (PUCT)

Appeal of the Texas 2015 Electric Rate Case Decision — In April 2016, SPS filed an appeal, with the Texas State District Court, of the PUCT’s order that had denied SPS’ request for rehearing on certain items in SPS’ Texas 2015 electric rate case related to capital structure, incentive compensation and wholesale load reductions.

In 2014, SPS had requested an overall retail electric revenue rate increase of $64.8 million, which it subsequently revised to $42.1 million. In 2015, the PUCT approved an overall rate decrease of approximately $4.0 million, net of rate case expenses.

The hearing in the appeal is scheduled for February 2017.

Texas 2015 Electric Rate Net Refund Case — Under an agreement in the Texas 2015 electric rate case, the final rates were retroactively applied to June 11, 2015. In June 2016, SPS filed an application to provide a net refund of approximately $1.25 million to reflect the difference in revenue SPS would have received for usage had SPS been charging the final rates approved by the PUCT from June 11, 2015 through Jan. 31, 2016. SPS has proposed to make the net refund over a six-month period beginning October 2016. The application is pending before the PUCT.

Texas 2016 Electric Rate Case — In February 2016, SPS filed a retail electric, non-fuel rate case in Texas with each of its Texas municipalities and the PUCT requesting an overall increase in annual base rate revenue of approximately $71.9 million, or 14.4 percent. The filing is based on a historic test year (HTY) ended Sept. 30, 2015, a requested return on equity (ROE) of 10.25 percent, an electric rate base of approximately $1.7 billion, and an equity ratio of 53.97 percent. In April 2016, SPS revised its requested rate increase to $68.6 million.

The following table summarizes the revised net request:

(Millions of Dollars)	Request
Capital expenditure investments	$	38.9
Change in jurisdictional allocation factors	9.8
Changes in ROE and capital structure	11.6
Estimated rate case expenses	4.5
Other, net	3.8
Total	$	68.6

Key dates in the procedural schedule are as follows:

• Intervenor direct testimony — Aug. 16, 2016;

• PUCT Staff direct testimony — Aug. 23, 2016;

• PUCT Staff and Intervenors’ cross-rebuttal testimony — Sept. 7, 2016;

• SPS’ rebuttal testimony — Sept. 9, 2016; and

• Hearings — Sept. 27 - Oct. 7, 2016.

SPS and various parties are having discussions regarding a potential settlement of the rate case. The final rates established at the end of the case are expected to be effective retroactive to July 20, 2016. A PUCT decision is expected in the first quarter of 2017.

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

New Mexico 2015 Electric Rate Case — In October 2015, SPS filed an electric rate case with the NMPRC seeking an increase in non-fuel base rates of $45.4 million. The proposed increase would be offset by a decrease in base fuel revenue of approximately $21.1 million. The rate filing is based on a June 30, 2015 HTY adjusted for known and measurable changes, a requested ROE of 10.25 percent, an electric rate base of approximately $734 million and an equity ratio of 53.97 percent.

In May 2016, SPS, the NMPRC Staff and all other parties filed a unanimous black-box stipulation that resolves all issues in the case. Under the stipulation, SPS will implement a non-fuel base rate increase of $23.5 million and a decrease in base fuel revenue of approximately $21.1 million. The decrease in base fuel revenue will be reflected in adjustments collected through the fuel and purchased power cost adjustment clause. The stipulation places no restriction on when SPS may file its next base rate case.

In July 2016, the hearing examiner issued a recommendation that the NMPRC approve the stipulation. The stipulation is subject to approval by the NMPRC and a decision on the settlement and implementation of final rates is expected in fall of 2016.

Pending Regulatory Proceedings — Federal Energy Regulatory Commission (FERC)

Southwest Power Pool, Inc. (SPP) Open Access Transmission Tariff (OATT) Upgrade Costs — Under the SPP OATT, costs of participant-funded, or “sponsored,” transmission upgrades may be recovered, in part, from other SPP customers whose transmission service depends on capacity enabled by the upgrade.  The SPP OATT has allowed SPP to collect charges since 2008, but to date SPP has not charged its customers any amounts attributable to these upgrades. 

In April 2016, SPP filed a request with the FERC for a waiver that would allow SPP to recover the charges not billed since 2008.  The FERC approved the waiver request in July 2016.  SPS is considering whether to seek clarification or rehearing of the FERC order.  SPP has indicated it anticipates completing its process and invoicing customers during the fourth quarter of 2016.  SPS estimates the charges to be $5 million to $10 million, based on preliminary information. SPS anticipates these costs would be recoverable through regulatory mechanisms.

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Commitments and Contingencies

6 Months Ended

Jun. 30, 2016

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 Notes 10 and 11 to the financial statements included in SPS’ Annual Report on Form 10-K for the year ended Dec. 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, 2016 and Dec. 31, 2015, 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

Air

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 United States Environmental Protection Agency (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 national parks and wilderness areas. Under BART, regional haze plans identify facilities that will have to reduce sulfur dioxide (SO₂), nitrogen oxide (NOx) and particulate matter (PM) emissions and set emission limits for those facilities. BART requirements can also be met through participation in interstate emission trading programs such as the Clean Air Interstate Rule (CAIR) and its successor, Cross-State Air Pollution Rule (CSAPR).

Texas developed a state implementation plan (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 December 2014, the EPA proposed to approve the BART portion of the SIP, with the exception that the EPA would substitute the CSAPR compliance for Texas’ reliance on CAIR. In January 2016, the EPA adopted a final rule that defers its approval of CSAPR compliance as BART until the EPA considers further adjustments to CSAPR emission budgets under the United States Court of Appeals for the District of Columbia Circuit’s (D.C. Circuit) remand of the Texas SO₂ emission budgets. In March 2016, the EPA requested information under the Clean Air Act (CAA) related to EGUs at SPS’ plants. SPS identified Harrington Units 1 and 2, Jones Units 1 and 2, Nichols Unit 3 and Plant X Unit 4 as BART-eligible units. These units will be evaluated based on their impact on visibility. Additional emission control equipment under the EPA’s BART guidelines for PM, SO₂ and NOx could be required if a unit is determined to “cause or contribute” to visibility impairment. SPS cannot evaluate the impact of additional emission controls until the EPA concludes its evaluation of BART. The EPA is expected to issue a proposed rule in December 2016. In June 2016, the EPA issued a memorandum which allows Texas to voluntarily adopt the CSAPR emission budgets limiting annual SO₂ and NOx emissions and rely on those emission budgets to satisfy Texas’ BART obligations under the regional haze rules. It is not yet known whether the Texas Commission on Environmental Quality (TCEQ) intends to utilize this option.

In December 2014, the EPA proposed to disapprove the reasonable progress portions of the SIP and instead adopt a federal implementation plan (FIP). In January 2016, the EPA adopted a final rule establishing a FIP for the state of Texas. As part of this final rule, the EPA imposed SO₂ emission limitations that reflect the installation of dry scrubbers on Tolk Units 1 and 2, with compliance required by February 2021. Investment costs associated with dry scrubbers could be approximately $600 million. In March 2016, SPS appealed the EPA’s decision and asked for a stay of the final rule while it is being reviewed. In July 2016, the United States Court of Appeals for the Fifth Circuit (Fifth Circuit) granted the stay motion and decided that the Fifth Circuit, not the D.C. Circuit, is the appropriate venue for this case. In addition, SPS filed a petition with the EPA requesting reconsideration of the final rule. SPS believes these costs would be recoverable through regulatory mechanisms if required, 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. 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. In June 2016, the EPA issued final designations which found the area near the Tolk plant to be meeting the NAAQS and the area near the Harrington plant as “unclassifiable.” The area near the Harrington plant is to be monitored for three years and a final designation is expected to be made by December 2020.

If an area is designated nonattainment in 2020, the respective states will need to evaluate all SO₂ sources in the area. The state would then submit an implementation plan, which would be due by 2022, designed to achieve the NAAQS by 2025. The TCEQ could require additional SO₂ controls at Harrington as part of such a plan. SPS cannot evaluate the impacts until the designation of nonattainment areas is made and any required state plans are developed. SPS believes that, should 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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Borrowings and Other Financing Instruments

6 Months Ended

Jun. 30, 2016

Debt Disclosure [Abstract]

Borrowings and Other Financing Instruments

Borrowings and Other Financing Instruments

Short-Term Borrowings

Money Pool — Xcel Energy Inc. and its utility subsidiaries have established a money pool arrangement that allows for short-term investments in and borrowings between the utility subsidiaries. Xcel Energy Inc. may make investments in the utility subsidiaries at market-based interest rates; however, the money pool arrangement does not allow the utility subsidiaries to make investments in Xcel Energy Inc. Money pool borrowings for SPS were as follows:

(Amounts in Millions, Except Interest Rates)	Three Months Ended June 30, 2016			Year Ended Dec. 31, 2015
Borrowing limit	$	100		$	100
Amount outstanding at period end	100			—
Average amount outstanding	50			21
Maximum amount outstanding	100			100
Weighted average interest rate, computed on a daily basis	0.64		%	0.40		%
Weighted average interest rate at period end	0.62			N/A

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, 2016			Year Ended Dec. 31, 2015
Borrowing limit	$	400		$	400
Amount outstanding at period end	25			15
Average amount outstanding	71			100
Maximum amount outstanding	140			246
Weighted average interest rate, computed on a daily basis	0.67		%	0.46		%
Weighted average interest rate at period end	0.65			0.60

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, 2016 and Dec. 31, 2015, there were $7 million of letters of credit outstanding under the credit facility. The contract amounts of these letters of credit approximate their fair value and are subject to fees.

Credit Facility — In order to use its commercial paper program, SPS must have a 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 credit facility capacity. 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, 2016, SPS had the following committed credit facility available (in millions of dollars):

Credit Facility (a)		Drawn(b)		Available
$	400	$	32	$	368

^(a)  This credit facility expires in June 2021.

^(b)  Includes outstanding commercial paper and letters of credit.

All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity under the credit facility. SPS had no direct advances on the credit facility outstanding at June 30, 2016 and Dec. 31, 2015.

Amended Credit Agreements - In June 2016, SPS entered into an amended five-year credit agreement with a syndicate of banks. The total borrowing limit under the amended credit agreement remained at $400 million. The amended credit agreement has substantially the same terms and conditions as the prior credit agreement with the following exceptions:

• The maturity extended from October 2019 to June 2021.

• The Eurodollar borrowing margins on these lines of credit were reduced to a range of 75 to 150 basis points per year, from a range of 87.5 to 175 basis points per year, based upon applicable long-term credit ratings.

• The commitment fees, calculated on the unused portion of the lines of credit, were reduced to a range of 6 to 22.5 basis points per year, from a range of 7.5 to 27.5 basis points per year, also based on applicable long-term credit ratings.

SPS has the right to request an extension of the revolving credit facility termination date for two additional one-year periods, subject to majority bank group approval.

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Fair Value of Financial Assets and Liabilities

6 Months Ended

Jun. 30, 2016

Fair Value Disclosures [Abstract]

Fair Value of Financial Assets and Liabilities

Fair Value of Financial Assets and Liabilities

Fair Value Measurements

The accounting guidance for fair value measurements and disclosures provides a single definition of fair value and requires certain disclosures about assets and liabilities measured at fair value. A hierarchical framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value is established by this guidance. The three levels in the hierarchy are as follows:

Level 1 — Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. The types of assets and liabilities included in Level 1 are highly liquid and actively traded instruments with quoted prices.

Level 2 — Pricing inputs are other than quoted prices in active markets, but are either directly or indirectly observable as of the reporting date. The types of assets and liabilities included in Level 2 are typically either comparable to actively traded securities or contracts, or priced with models using highly observable inputs.

Level 3 — Significant inputs to pricing have little or no observability as of the reporting date. The types of assets and liabilities included in Level 3 are those valued with models requiring significant management judgment or estimation.

Specific valuation methods include the following:

Cash equivalents— The fair values of cash equivalents are generally based on cost plus accrued interest; money market funds are measured using quoted prices.

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, referred to as financial transmission rights (FTRs). FTRs purchased from a regional transmission organization (RTO) are financial instruments that entitle or obligate the holder to monthly revenues or charges based on transmission congestion across a given transmission path. The value of an FTR is derived from, and designed to offset, the cost of energy congestion, which is caused by transmission load and transmission constraints. Congestion is also influenced by the operating schedules of power plants and the consumption of electricity. Unplanned plant outages, scheduled plant maintenance, changes in the costs of fuels used in generation, weather and changes in demand for electricity can each impact the operating schedules of the power plants 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 fair value measurements for FTRs have been assigned a Level 3. Monthly settlements for non-trading FTRs 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, 2016, accumulated other comprehensive losses related to interest rate derivatives included $0.1 million of net losses expected to be reclassified into earnings during the next 12 months as the related hedged interest rate transactions impact earnings, including forecasted amounts for unsettled hedges, as applicable.

Wholesale and Commodity Trading Risk — SPS conducts various wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy and energy-related instruments. SPS’ risk management policy allows management to conduct these activities within guidelines and limitations as approved by its risk management committee.

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, 2016 and Dec. 31, 2015:

(Amounts in Thousands) (a)	June 30, 2016	Dec. 31, 2015
Megawatt hours of electricity	6,255	6,192

^(a)  Amounts are not reflective of net positions in the underlying commodities.

Impact of Derivative Activities on Income and Accumulated Other Comprehensive Loss — Pre-tax losses related to interest rate derivatives reclassified from accumulated other comprehensive loss into earnings were $0.1 million for the three and six months ended June 30, 2016 and 2015.

During the three and six months ended June 30, 2016, changes in the fair value of FTRs resulted in pre-tax net gains of $0.5 million and $1.8 million, respectively and were recognized as regulatory assets and liabilities. For 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. The classification as a regulatory asset or liability is based on expected recovery of FTR settlements through fuel and purchased energy cost recovery mechanisms.

FTR settlement losses of $3.1 million and $3.2 million were recognized for the three and six months ended June 30, 2016, recorded to electric fuel and purchased power. For the three and six months ended June 30, 2015, FTR settlement gains of $1.7 million and $1.6 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, 2016 and 2015. 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 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. 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 , 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 are contracts with counterparties to its wholesale, trading and non-trading commodity and transmission activities. At June 30, 2016, eight of the most significant counterparties, comprising $46.5 million or 53 percent of this credit exposure, were not rated by Standard & Poor’s Ratings Services, Moody’s Investor Services or Fitch Ratings, but based on SPS’ internal analysis, had credit quality consistent with investment grade. Another of these significant counterparties, comprising $0.5 million or 1 percent of this credit exposure, had credit quality less than investment grade, based on ratings from external analysis. 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, 2016:

	June 30, 2016
	Fair Value						Fair Value Total		Counterparty Netting (b)
(Thousands of Dollars)	Level 1		Level 2		Level 3							Total
Current derivative assets
Other derivative instruments:
Electric commodity	$	—	$	—	$	4,021	$	4,021	$	(2,951	)	$	1,070
Total current derivative assets	$	—	$	—	$	4,021	$	4,021	$	(2,951	)	1,070
PPAs (a)												5,526
Current derivative instruments												$	6,596
Noncurrent derivative assets
PPAs (a)												$	23,692
Noncurrent derivative instruments												$	23,692
Current derivative liabilities
Other derivative instruments:
Electric commodity	$	—	$	—	$	2,951	$	2,951	$	(2,951	)	$	—
Total current derivative liabilities	$	—	$	—	$	2,951	$	2,951	$	(2,951	)	—
PPAs (a)												3,565
Current derivative instruments												$	3,565
Noncurrent derivative liabilities
PPAs (a)												$	25,296
Noncurrent derivative instruments												$	25,296

^(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, 2016. At June 30, 2016, derivative assets and liabilities include no obligations to return cash collateral or rights to reclaim cash collateral. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.

The following table presents for each of the fair value hierarchy levels, SPS’ derivative assets and liabilities measured at fair value on a recurring basis at Dec. 31, 2015:

	Dec. 31, 2015
	Fair Value						Fair Value Total		Counterparty Netting (b)
(Thousands of Dollars)	Level 1		Level 2		Level 3							Total
Current derivative assets
Other derivative instruments:
Electric commodity	$	—	$	—	$	8,980	$	8,980	$	(3,920	)	$	5,060
Total current derivative assets	$	—	$	—	$	8,980	$	8,980	$	(3,920	)	5,060
PPAs (a)												7,892
Current derivative instruments												$	12,952
Noncurrent derivative assets
PPAs (a)												$	25,272
Noncurrent derivative instruments												$	25,272
Current derivative liabilities
Other derivative instruments:
Electric commodity	$	—	$	—	$	3,920	$	3,920	$	(3,920	)	$	—
Total current derivative liabilities	$	—	$	—	$	3,920	$	3,920	$	(3,920	)	—
PPAs (a)												3,565
Current derivative instruments												$	3,565
Noncurrent derivative liabilities
PPAs (a)												$	27,078
Noncurrent derivative instruments												$	27,078

^(a)  In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, SPS began recording several long-term PPAs at fair value due to accounting requirements related to underlying price adjustments. As these purchases are recovered through normal regulatory recovery mechanisms in the respective jurisdictions, the changes in fair value for these contracts were offset by regulatory assets and liabilities. During 2006, SPS qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.

^(b)  SPS nets derivative instruments and related collateral in its balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Dec. 31, 2015. At Dec. 31, 2015, derivative assets and liabilities include no obligations to return cash collateral or rights to reclaim cash collateral. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.

The following table presents the changes in Level 3 commodity derivatives for the three and six months ended June 30, 2016 and 2015:

	Three Months Ended June 30
(Thousands of Dollars)	2016			2015
Balance at April 1	$	1,730		$	6,457
Purchases	1,956			17,284
Settlements	(7,130		)	(10,022		)
Net transactions recorded during the period:
Gains (losses) recognized as regulatory assets and liabilities	4,514			(2,256		)
Balance at June 30	$	1,070		$	11,463

	Six Months Ended June 30
(Thousands of Dollars)	2016			2015
Balance at Jan. 1	$	5,060		$	15,884
Purchases	3,800			22,213
Settlements	(14,122		)	(18,400		)
Net transactions recorded during the period:
Gains (losses) recognized as regulatory assets and liabilities	6,332			(8,234		)
Balance at June 30	$	1,070		$	11,463

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, 2016 and 2015.

Fair Value of Long-Term Debt

As of June 30, 2016 and Dec. 31, 2015, other financial instruments for which the carrying amount did not equal fair value were as follows:

	June 30, 2016				Dec. 31, 2015
(Thousands of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion (a)	$	1,539,177	$	1,775,895	$	1,538,522	$	1,678,673

^(a)  Amounts reflect the classification of debt issuance costs as a deduction from the carrying amount of the related debt. See Note 2, Accounting Pronouncements for more information on the adoption of ASU 2015-03.

The fair value of SPS’ long-term debt is estimated based on recent trades and observable spreads from benchmark interest rates for similar securities. The fair value estimates are based on information available to management as of June 30, 2016 and Dec. 31, 2015, and given the observability of the inputs to these estimates, the fair values presented for long-term debt have been assigned a Level 2.

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Other Income, Net

6 Months Ended

Jun. 30, 2016

Other Income and Expenses [Abstract]

Other Income, Net

Other Income, Net

Other income, net consisted of the following:

	Three Months Ended    June 30				Six Months Ended   June 30
(Thousands of Dollars)	2016		2015		2016		2015
Interest income	$	94	$	13	$	179	$	45
Other nonoperating income	298		65		247		110
Insurance policy income (expense)	—		78		—		(55		)
Other income, net	$	392	$	156	$	426	$	100

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Benefit Plans and Other Postretirement Benefits

6 Months Ended

Jun. 30, 2016

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
	2016			2015			2016			2015
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Service cost	$	2,440		$	2,751		$	194		$	238
Interest cost	5,315			5,046			455			437
Expected return on plan assets	(6,901		)	(7,152		)	(594		)	(635		)
Amortization of prior service cost (credit)	—			10			(100		)	(100		)
Amortization of net loss (gain)	2,997			3,772			(146		)	(160		)
Net periodic benefit cost (credit)	3,851			4,427			(191		)	(220		)
Credits recognized due to the effects of regulation	638			686			—			—
Net benefit cost (credit) recognized for financial reporting	$	4,489		$	5,113		$	(191	)	$	(220	)

	Six Months Ended   June 30
	2016			2015			2016			2015
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Service cost	$	4,880		$	5,503		$	388		$	477
Interest cost	10,630			10,092			910			873
Expected return on plan assets	(13,802		)	(14,305		)	(1,188		)	(1,270		)
Amortization of prior service cost (credit)	—			20			(200		)	(200		)
Amortization of net loss (gain)	5,994			7,544			(292		)	(320		)
Net periodic benefit cost (credit)	7,702			8,854			(382		)	(440		)
Credits recognized due to the effects of regulation	716			1,399			—			—
Net benefit cost (credit) recognized for financial reporting	$	8,418		$	10,253		$	(382	)	$	(440	)

In January 2016, contributions of $125.0 million were made across four of Xcel Energy’s pension plans, of which $18.0 million was attributable to SPS. Xcel Energy does not expect additional pension contributions during 2016.

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Other Comprehensive Income

6 Months Ended

Jun. 30, 2016

Stockholders' Equity Note [Abstract]

Other Comprehensive Income

anges in accumulated other comprehensive loss, net of tax, for the three and six months ended June 30, 2016 and 2015 were as follows:

	Three Months Ended June 30, 2016
(Thousands of Dollars)	Gains and Losses on Cash Flow Hedges			Defined Benefit and Postretirement Items			Total
Accumulated other comprehensive loss at April 1	$	(775	)	$	(452	)	$	(1,227	)
Other comprehensive loss before reclassifications	—			11			11
Losses reclassified from net accumulated other comprehensive loss	43			—			43
Net current period other comprehensive income	43			11			54
Accumulated other comprehensive loss at June 30	$	(732	)	$	(441	)	$	(1,173	)

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

	Six Months Ended June 30, 2016
(Thousands of Dollars)	Gains and Losses on Cash Flow Hedges			Defined Benefit and Postretirement Items			Total
Accumulated other comprehensive loss at Jan. 1	$	(817	)	$	(464	)	$	(1,281	)
Other comprehensive loss before reclassifications	—			23			23
Losses reclassified from net accumulated other comprehensive loss	85			—			85
Net current period other comprehensive income	85			23			108
Accumulated other comprehensive loss at June 30	$	(732	)	$	(441	)	$	(1,173	)

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

Reclassifications from accumulated other comprehensive loss for the three and six months ended June 30, 2016 and 2015 were as follows:

	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Three Months Ended June 30, 2016				Three Months Ended June 30, 2015
Losses on cash flow hedges:
Interest rate derivatives	$	67		(a)	$	67		(a)
Total, pre-tax	67				67
Tax benefit	(24		)		(24		)
Total amounts reclassified, net of tax	$	43			$	43

	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Six Months Ended June 30, 2016				Six Months Ended June 30, 2015
Losses on cash flow hedges:
Interest rate derivatives	$	134		(a)	$	133		(a)
Total, pre-tax	134				133
Tax benefit	(49		)		(48		)
Total amounts reclassified, net of tax	$	85			$	85

^(a)  Included in interest charges.

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Selected Balance Sheet Data (Tables)

6 Months Ended

Jun. 30, 2016

Balance Sheet Related Disclosures [Abstract]

Accounts Receivable, Net

(Thousands of Dollars)	June 30, 2016			Dec. 31, 2015
Accounts receivable, net
Accounts receivable	$	89,872		$	77,054
Less allowance for bad debts	(5,864		)	(5,888		)
	$	84,008		$	71,166

Inventories

(Thousands of Dollars)	June 30, 2016		Dec. 31, 2015
Inventories
Materials and supplies	$	25,525	$	24,888
Fuel	6,132		12,658
	$	31,657	$	37,546

Property, Plant and Equipment, Net

(Thousands of Dollars)	June 30, 2016			Dec. 31, 2015
Property, plant and equipment, net
Electric plant	$	6,119,713		$	5,933,764
Construction work in progress	277,974			236,697
Total property, plant and equipment	6,397,687			6,170,461
Less accumulated depreciation	(1,877,015		)	(1,821,638		)
	$	4,520,672		$	4,348,823

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Income Taxes (Tables)

6 Months Ended

Jun. 30, 2016

Income Tax Disclosure [Abstract]

Reconciliation of Unrecognized Tax Benefits

A reconciliation of the amount of unrecognized tax benefit is as follows:

(Millions of Dollars)	June 30, 2016		Dec. 31, 2015
Unrecognized tax benefit — Permanent tax positions	$	2.7	$	2.6
Unrecognized tax benefit — Temporary tax positions	21.9		22.1
Total unrecognized tax benefit	$	24.6	$	24.7

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, 2016			Dec. 31, 2015
NOL and tax credit carryforwards	$	(5.2	)	$	(5.0	)

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Rate Matters (Tables)

6 Months Ended

Jun. 30, 2016

Public Utilities, General Disclosures [Abstract]

SPS' Texas 2016 Electric Rate Case [Table Text Block]

The following table summarizes the revised net request:

(Millions of Dollars)	Request
Capital expenditure investments	$	38.9
Change in jurisdictional allocation factors	9.8
Changes in ROE and capital structure	11.6
Estimated rate case expenses	4.5
Other, net	3.8
Total	$	68.6

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Borrowings and Other Financing Instruments (Tables)

6 Months Ended

Jun. 30, 2016

Borrowings and Other Financing Instruments [Abstract]

Credit Facilities

At June 30, 2016, SPS had the following committed credit facility available (in millions of dollars):

Credit Facility (a)		Drawn(b)		Available
$	400	$	32	$	368

^(a)  This credit facility expires in June 2021.

^(b)  Includes outstanding commercial paper and letters of credit.

Money Pool

Borrowings and Other Financing Instruments [Abstract]

Short-Term Borrowings

Money pool borrowings for SPS were as follows:

(Amounts in Millions, Except Interest Rates)	Three Months Ended June 30, 2016			Year Ended Dec. 31, 2015
Borrowing limit	$	100		$	100
Amount outstanding at period end	100			—
Average amount outstanding	50			21
Maximum amount outstanding	100			100
Weighted average interest rate, computed on a daily basis	0.64		%	0.40		%
Weighted average interest rate at period end	0.62			N/A

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, 2016			Year Ended Dec. 31, 2015
Borrowing limit	$	400		$	400
Amount outstanding at period end	25			15
Average amount outstanding	71			100
Maximum amount outstanding	140			246
Weighted average interest rate, computed on a daily basis	0.67		%	0.46		%
Weighted average interest rate at period end	0.65			0.60

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Fair Value of Financial Assets and Liabilities (Tables)

6 Months Ended

Jun. 30, 2016

Fair Value Disclosures [Abstract]

Gross Notional Amounts of Commodity FTRs

The following table details the gross notional amounts of commodity FTRs at June 30, 2016 and Dec. 31, 2015:

(Amounts in Thousands) (a)	June 30, 2016	Dec. 31, 2015
Megawatt hours of electricity	6,255	6,192

^(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, 2016:

	June 30, 2016
	Fair Value						Fair Value Total		Counterparty Netting (b)
(Thousands of Dollars)	Level 1		Level 2		Level 3							Total
Current derivative assets
Other derivative instruments:
Electric commodity	$	—	$	—	$	4,021	$	4,021	$	(2,951	)	$	1,070
Total current derivative assets	$	—	$	—	$	4,021	$	4,021	$	(2,951	)	1,070
PPAs (a)												5,526
Current derivative instruments												$	6,596
Noncurrent derivative assets
PPAs (a)												$	23,692
Noncurrent derivative instruments												$	23,692
Current derivative liabilities
Other derivative instruments:
Electric commodity	$	—	$	—	$	2,951	$	2,951	$	(2,951	)	$	—
Total current derivative liabilities	$	—	$	—	$	2,951	$	2,951	$	(2,951	)	—
PPAs (a)												3,565
Current derivative instruments												$	3,565
Noncurrent derivative liabilities
PPAs (a)												$	25,296
Noncurrent derivative instruments												$	25,296

^(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, 2016. At June 30, 2016, derivative assets and liabilities include no obligations to return cash collateral or rights to reclaim cash collateral. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.

The following table presents for each of the fair value hierarchy levels, SPS’ derivative assets and liabilities measured at fair value on a recurring basis at Dec. 31, 2015:

	Dec. 31, 2015
	Fair Value						Fair Value Total		Counterparty Netting (b)
(Thousands of Dollars)	Level 1		Level 2		Level 3							Total
Current derivative assets
Other derivative instruments:
Electric commodity	$	—	$	—	$	8,980	$	8,980	$	(3,920	)	$	5,060
Total current derivative assets	$	—	$	—	$	8,980	$	8,980	$	(3,920	)	5,060
PPAs (a)												7,892
Current derivative instruments												$	12,952
Noncurrent derivative assets
PPAs (a)												$	25,272
Noncurrent derivative instruments												$	25,272
Current derivative liabilities
Other derivative instruments:
Electric commodity	$	—	$	—	$	3,920	$	3,920	$	(3,920	)	$	—
Total current derivative liabilities	$	—	$	—	$	3,920	$	3,920	$	(3,920	)	—
PPAs (a)												3,565
Current derivative instruments												$	3,565
Noncurrent derivative liabilities
PPAs (a)												$	27,078
Noncurrent derivative instruments												$	27,078

^(a)  In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, SPS began recording several long-term PPAs at fair value due to accounting requirements related to underlying price adjustments. As these purchases are recovered through normal regulatory recovery mechanisms in the respective jurisdictions, the changes in fair value for these contracts were offset by regulatory assets and liabilities. During 2006, SPS qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.

^(b)  SPS nets derivative instruments and related collateral in its balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Dec. 31, 2015. At Dec. 31, 2015, derivative assets and liabilities include no obligations to return cash collateral or rights to reclaim cash collateral. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.

Changes in Level 3 Commodity Derivatives

The following table presents the changes in Level 3 commodity derivatives for the three and six months ended June 30, 2016 and 2015:

	Three Months Ended June 30
(Thousands of Dollars)	2016			2015
Balance at April 1	$	1,730		$	6,457
Purchases	1,956			17,284
Settlements	(7,130		)	(10,022		)
Net transactions recorded during the period:
Gains (losses) recognized as regulatory assets and liabilities	4,514			(2,256		)
Balance at June 30	$	1,070		$	11,463

	Six Months Ended June 30
(Thousands of Dollars)	2016			2015
Balance at Jan. 1	$	5,060		$	15,884
Purchases	3,800			22,213
Settlements	(14,122		)	(18,400		)
Net transactions recorded during the period:
Gains (losses) recognized as regulatory assets and liabilities	6,332			(8,234		)
Balance at June 30	$	1,070		$	11,463

Carrying Amount and Fair Value of Long-term Debt

As of June 30, 2016 and Dec. 31, 2015, other financial instruments for which the carrying amount did not equal fair value were as follows:

	June 30, 2016				Dec. 31, 2015
(Thousands of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion (a)	$	1,539,177	$	1,775,895	$	1,538,522	$	1,678,673

^(a)  Amounts reflect the classification of debt issuance costs as a deduction from the carrying amount of the related debt. See Note 2, Accounting Pronouncements for more information on the adoption of ASU 2015-03.

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Other Income, Net (Tables)

6 Months Ended

Jun. 30, 2016

Other Income and Expenses [Abstract]

Other Income, Net

Other income, net consisted of the following:

	Three Months Ended    June 30				Six Months Ended   June 30
(Thousands of Dollars)	2016		2015		2016		2015
Interest income	$	94	$	13	$	179	$	45
Other nonoperating income	298		65		247		110
Insurance policy income (expense)	—		78		—		(55		)
Other income, net	$	392	$	156	$	426	$	100

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Benefit Plans and Other Postretirement Benefits (Tables)

6 Months Ended

Jun. 30, 2016

Compensation and Retirement Disclosure [Abstract]

Components of Net Periodic Benefit Cost (Credit)

Components of Net Periodic Benefit Cost (Credit)

	Three Months Ended    June 30
	2016			2015			2016			2015
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Service cost	$	2,440		$	2,751		$	194		$	238
Interest cost	5,315			5,046			455			437
Expected return on plan assets	(6,901		)	(7,152		)	(594		)	(635		)
Amortization of prior service cost (credit)	—			10			(100		)	(100		)
Amortization of net loss (gain)	2,997			3,772			(146		)	(160		)
Net periodic benefit cost (credit)	3,851			4,427			(191		)	(220		)
Credits recognized due to the effects of regulation	638			686			—			—
Net benefit cost (credit) recognized for financial reporting	$	4,489		$	5,113		$	(191	)	$	(220	)

	Six Months Ended   June 30
	2016			2015			2016			2015
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Service cost	$	4,880		$	5,503		$	388		$	477
Interest cost	10,630			10,092			910			873
Expected return on plan assets	(13,802		)	(14,305		)	(1,188		)	(1,270		)
Amortization of prior service cost (credit)	—			20			(200		)	(200		)
Amortization of net loss (gain)	5,994			7,544			(292		)	(320		)
Net periodic benefit cost (credit)	7,702			8,854			(382		)	(440		)
Credits recognized due to the effects of regulation	716			1,399			—			—
Net benefit cost (credit) recognized for financial reporting	$	8,418		$	10,253		$	(382	)	$	(440	)

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Other Comprehensive Income (Tables)

6 Months Ended

Jun. 30, 2016

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, 2016 and 2015 were as follows:

	Three Months Ended June 30, 2016
(Thousands of Dollars)	Gains and Losses on Cash Flow Hedges			Defined Benefit and Postretirement Items			Total
Accumulated other comprehensive loss at April 1	$	(775	)	$	(452	)	$	(1,227	)
Other comprehensive loss before reclassifications	—			11			11
Losses reclassified from net accumulated other comprehensive loss	43			—			43
Net current period other comprehensive income	43			11			54
Accumulated other comprehensive loss at June 30	$	(732	)	$	(441	)	$	(1,173	)

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

	Six Months Ended June 30, 2016
(Thousands of Dollars)	Gains and Losses on Cash Flow Hedges			Defined Benefit and Postretirement Items			Total
Accumulated other comprehensive loss at Jan. 1	$	(817	)	$	(464	)	$	(1,281	)
Other comprehensive loss before reclassifications	—			23			23
Losses reclassified from net accumulated other comprehensive loss	85			—			85
Net current period other comprehensive income	85			23			108
Accumulated other comprehensive loss at June 30	$	(732	)	$	(441	)	$	(1,173	)

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

Reclassifications out of Accumulated Other Comprehensive Loss

Reclassifications from accumulated other comprehensive loss for the three and six months ended June 30, 2016 and 2015 were as follows:

	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Three Months Ended June 30, 2016				Three Months Ended June 30, 2015
Losses on cash flow hedges:
Interest rate derivatives	$	67		(a)	$	67		(a)
Total, pre-tax	67				67
Tax benefit	(24		)		(24		)
Total amounts reclassified, net of tax	$	43			$	43

	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Six Months Ended June 30, 2016				Six Months Ended June 30, 2015
Losses on cash flow hedges:
Interest rate derivatives	$	134		(a)	$	133		(a)
Total, pre-tax	134				133
Tax benefit	(49		)		(48		)
Total amounts reclassified, net of tax	$	85			$	85

^(a)  Included in interest charges.

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Accounting Pronouncements Debt Issuance Costs (Details) - Accounting Standards Update 2015-03 - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015
Long-term Debt
Debt Instrument [Line Items]
Reclassification of deferred debt issuance costs, net	$ 11.8	$ 12.1
Other Noncurrent Assets
Debt Instrument [Line Items]
Reclassification of deferred debt issuance costs, net		$ (12.1)

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Selected Balance Sheet Data (Details) - USD ($) $ in Thousands	Jun. 30, 2016	Dec. 31, 2015
Accounts receivable, net
Accounts receivable	$ 89,872	$ 77,054
Less allowance for bad debts	(5,864)	(5,888)
Accounts receivable, net	$ 84,008	$ 71,166

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Selected Balance Sheet Data Balance Sheet Related Disclosures, Inventories (Details) - USD ($) $ in Thousands	Jun. 30, 2016	Dec. 31, 2015
Public Utilities, Inventory [Line Items]
Inventories	$ 31,657	$ 37,546
Materials and supplies
Public Utilities, Inventory [Line Items]
Inventories	25,525	24,888
Fuel
Public Utilities, Inventory [Line Items]
Inventories	$ 6,132	$ 12,658

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Selected Balance Sheet Data Balance Sheet Related Disclosures, Property, Plant and Equipment (Details) - USD ($) $ in Thousands	Jun. 30, 2016	Dec. 31, 2015
Public Utility, Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	$ 6,397,687	$ 6,170,461
Less accumulated depreciation	(1,877,015)	(1,821,638)
Property, plant and equipment, net	4,520,672	4,348,823
Electric plant
Public Utility, Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	6,119,713	5,933,764
Construction work in progress
Public Utility, Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	$ 277,974	$ 236,697

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Income Taxes (Details) - USD ($)	1 Months Ended	6 Months Ended	9 Months Ended	12 Months Ended
	Feb. 29, 2016	Jun. 30, 2016	Sep. 30, 2015	Dec. 31, 2012	Dec. 31, 2015
Unrecognized Tax Benefits [Abstract]
Unrecognized tax benefit - Permanent tax positions		$ 2,700,000			$ 2,600,000
Unrecognized tax benefit - Temporary tax positions		21,900,000			22,100,000
Total unrecognized tax benefit		24,600,000			24,700,000
NOL and tax credit carryforwards		(5,200,000)			(5,000,000)
Upper bound of decrease in unrecognized tax benefit that is reasonably possible		7,000,000
Amounts accrued for penalties related to unrecognized tax benefits		$ 0			$ 0
Internal Revenue Service (IRS)
Tax Audits [Abstract]
Earliest year subject to examination		2009
Year(s) under examination			2012 and 2013	2010 and 2011
Year of carryback claim under examination				2009
Potential Tax Adjustments		$ 14,000,000
State Jurisdiction (Texas)
Tax Audits [Abstract]
Earliest year subject to examination		2009
Year(s) under examination	2009 and 2010

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Rate Matters (Details) - USD ($) $ in Thousands	1 Months Ended					6 Months Ended	12 Months Ended
	May 31, 2016	Apr. 30, 2016	Feb. 29, 2016	Oct. 31, 2015	Jun. 30, 2015	Jun. 30, 2016	Dec. 31, 2015	Dec. 31, 2014
PUCT Proceeding - Appeal of the Texas 2015 Electric Rate Case Decision [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount					$ 42,100			$ 64,800
PUCT Proceeding -Texas 2015 Electric Rate Net Refund Case [Member]
Public Utilities, General Disclosures [Line Items]
Customer Refund Liability, Current						$ 1,250
Length of refund period						6 months
PUCT Proceeding - Texas 2016 Electric Rate Case
Public Utilities, General Disclosures [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount			$ 71,900
Public Utilities, Requested Rate Increase (Decrease), Percentage			14.40%
Public Utilities, Requested Return on Equity, Percentage			10.25%
Public Utilities, Requested Rate Base, Amount			$ 1,700,000
Public Utilities, Requested Equity Capital Structure, Percentage			53.97%
Public Utilities, Revised requested rate increase		$ 68,600
Public utilities, Requested Increase Related to Capital Investment		38,900
Public Utilities, Increase to Jurisdictional Allocation Factors		9,800
Public Utilities, ROE and Capital Structure		11,600
Public Utilities, Increase to Rate Case Expenses		4,500
Public Utilities, Increase Related To Other, Net		$ 3,800
NMPRC Proceeding - New Mexico 2015 Electric Rate Case
Public Utilities, General Disclosures [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount				$ 45,400
Public Utilities, Requested Return on Equity, Percentage				10.25%
Public Utilities, Requested Rate Base, Amount				$ 734,000
Public Utilities, Requested Equity Capital Structure, Percentage				53.97%
Public Utilities, Decrease In Base Fuel Revenues				$ 21,100
Public Utilities, Non-fuel Base Rate Increase Under the Stipulation	$ 23,500
Public Utilities, Decrease In Base Fuel Revenues Under the Stipulation	$ 21,100
Public Utility Commission of Texas (PUCT) | PUCT Proceeding - Appeal of the Texas 2015 Electric Rate Case Decision [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Approved Rate Decrease, Net of Rate Case Expenses							$ 4,000
Minimum | SPP Open Access Transmission Tariff Upgrade Costs
Public Utilities, General Disclosures [Line Items]
Public Utilities, Estimated Charges For Transmission Service Upgrades						$ 5,000
Maximum | SPP Open Access Transmission Tariff Upgrade Costs
Public Utilities, General Disclosures [Line Items]
Public Utilities, Estimated Charges For Transmission Service Upgrades						$ 10,000

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Commitments and Contingencies, Purchased Power Agreements (Details) - Independent Power Producing Entities - MW	6 Months Ended	12 Months Ended
	Jun. 30, 2016	Dec. 31, 2015
Purchased Power Agreements [Abstract]
Generating capacity (in MW)	827	827
Purchase Power Agreement Duration, Maximum	2033	2033

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Commitments and Contingencies, Environmental Contingencies - Unrecorded Unconditional Purchase Obligation (Details) $ in Millions	6 Months Ended
	Jun. 30, 2016 USD ($)
Implementation of the National Ambient Air Quality Standard for Sulfur Dioxide
Environmental Requirements [Abstract]
Number of phases under a consent decree which the EPA is requiring states to evaluate areas for attainment	3
Number of years unclassifiable areas will be monitored	3 years
Capital Addition Purchase Commitments | Regional Haze Rules
Environmental Requirements [Abstract]
Liability for estimated cost to comply with regulation	$ 600

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Borrowings and Other Financing Instruments, Short-Term Borrowings (Details) - USD ($)	3 Months Ended	12 Months Ended
	Jun. 30, 2016	Dec. 31, 2015
Short-term Debt [Line Items]
Amount outstanding at period end	$ 25,000,000	$ 15,000,000
Money Pool
Short-term Debt [Line Items]
Borrowing limit	100,000,000	100,000,000
Amount outstanding at period end	100,000,000	0
Average amount outstanding	50,000,000	21,000,000
Maximum amount outstanding	$ 100,000,000	$ 100,000,000
Weighted average interest rate, computed on a daily basis (percentage)	0.64%	0.40%
Weighted average interest rate at period end (percentage)	0.62%
Commercial Paper
Short-term Debt [Line Items]
Borrowing limit	$ 400,000,000	$ 400,000,000
Amount outstanding at period end	25,000,000	15,000,000
Average amount outstanding	71,000,000	100,000,000
Maximum amount outstanding	$ 140,000,000	$ 246,000,000
Weighted average interest rate, computed on a daily basis (percentage)	0.67%	0.46%
Weighted average interest rate at period end (percentage)	0.65%	0.60%

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Borrowings and Other Financing Instruments, Letters of Credit (Details) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2016	Dec. 31, 2015
Line of Credit Facility [Line Items]
Amount outstanding at period end	$ 25,000	$ 15,000
Letter of Credit
Line of Credit Facility [Line Items]
Amount outstanding at period end	$ 7,000	$ 7,000
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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Borrowings and Other Financing Instruments, Credit Facility (Details) - Credit Facility - USD ($)		6 Months Ended
		Jun. 30, 2016	Dec. 31, 2015
Line of Credit Facility [Line Items]
Debt Instrument, Maturity Date		Jun. 30, 2021
Credit Facility	[1]	$ 400,000,000
Drawn	[2]	32,000,000
Available		368,000,000
Direct advances on the credit facility outstanding		$ 0	$ 0

[1] This credit facility expires in June 2021.

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

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Borrowings and Other Financing Instruments Borrowings and Other Financing Instruments, Amended Credit Agreements (Details) - Credit Facility	6 Months Ended
	Jun. 30, 2016 USD ($)
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	$ 400,000,000	[1]
Debt Instrument, Maturity Date	Jun. 30, 2021
SPS [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Term	5 years
Number Of Additional Periods Revolving Termination Date Can Be Extended Subject To Majority Bank Group Approval	2
Term Of Each Additional Period Revolving Termination Date Can Be Extended Subject To Majority Bank Group Approval	1 year
SPS [Member] | Original Terms and Conditions [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Maturity Date	Oct. 31, 2019
Line Of Credit Facility Minimum Borrowing Margin Based On Long Term Credit Ratings	0.875%
Line Of Credit Facility Maximum Borrowing Margin Based On Long Term Credit Ratings	1.75%
Line Of Credit Facility Minimum Commitment Fees Calculated On Unused Portion Of Lines Of Credit	0.075%
Line Of Credit Facility Maximum Commitment Fees Calculated On Unused Portion Of Lines Of Credit	0.275%
SPS [Member] | Amended Terms and Conditions [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Maturity Date	Jun. 30, 2021
Line Of Credit Facility Minimum Borrowing Margin Based On Long Term Credit Ratings	0.75%
Line Of Credit Facility Maximum Borrowing Margin Based On Long Term Credit Ratings	1.50%
Line Of Credit Facility Minimum Commitment Fees Calculated On Unused Portion Of Lines Of Credit	0.06%
Line Of Credit Facility Maximum Commitment Fees Calculated On Unused Portion Of Lines Of Credit	0.225%

[1] This credit facility expires in June 2021.

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Fair Value of Financial Assets and Liabilities, Derivative Instruments (Details) MWh in Thousands, $ in Millions		Jun. 30, 2016 USD ($) MWh Counterparty	Dec. 31, 2015 MWh
Credit Concentration Risk | Municipal or Cooperative Entities or Other Utilities [Member]
Consideration of Credit Risk and Concentrations [Abstract]
Number of most significant counterparties for wholesale, trading and non-trading commodity activities with credit exposure | Counterparty		8
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		8
Wholesale, trading and non-trading commodity credit exposure for the most significant counterparties		$ 46.5
Percentage of wholesale, trading and non-trading commodity credit exposure for the most significant counterparties (in hundredths)		53.00%
Credit Concentration Risk | Credit Quality Less Than Investment Grade [Member]
Consideration of Credit Risk and Concentrations [Abstract]
Wholesale, trading and non-trading commodity credit exposure for the most significant counterparties		$ 0.5
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		$ (0.1)
Electric Commodity (in megawatt hours)
Gross Notional Amounts of Commodity FTRs [Abstract]
Derivative, Nonmonetary Notional amount | MWh	[1]	6,255	6,192

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

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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, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
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
Designated as Hedging Instrument | Cash Flow Hedges | Interest Rate
Impact of Derivative Activity on Accumulated Other Comprehensive Loss, Regulatory Assets and Liabilities, and Income [Abstract]
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 gains (losses) recognized during the period in regulatory (assets) and liabilities	500,000	(1,200,000)	1,800,000	(2,000,000)
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities)	$ 3,100,000	$ (1,700,000)	$ 3,200,000	$ (1,600,000)

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Fair Value of Financial Assets and Liabilities, Fair Value Measurements (Details) - USD ($)	Jun. 30, 2016		Dec. 31, 2015
Derivatives, Fair Value [Line Items]
Derivative Asset, Collateral, Obligation to Return Cash, Offset	$ 0		$ 0
Derivative Liability, Collateral, Right to Reclaim Cash, Offset	0		0
Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	6,596,000		12,952,000
Other Noncurrent Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	23,692,000		25,272,000
Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	3,565,000		3,565,000
Other Noncurrent Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	25,296,000		27,078,000
Fair Value Measured on a Recurring Basis | Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	1,070,000		5,060,000
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset	(2,951,000)	[1]	(3,920,000)	[2]
Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	1,070,000		5,060,000
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset	(2,951,000)	[1]	(3,920,000)	[2]
Fair Value Measured on a Recurring Basis | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset	(2,951,000)	[1]	(3,920,000)	[2]
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 Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset	(2,951,000)	[1]	(3,920,000)	[2]
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	4,021,000		8,980,000
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Assets | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	4,021,000		8,980,000
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	2,951,000		3,920,000
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Liabilities | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	2,951,000		3,920,000
Fair Value, Measurements, Nonrecurring | Other Current Assets | Purchased Power Agreements
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	5,526,000	[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	23,692,000	[3]	25,272,000	[4]
Fair Value, Measurements, Nonrecurring | Other Current Liabilities | Purchased Power Agreements
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	3,565,000	[3]	3,565,000	[4]
Fair Value, Measurements, Nonrecurring | Other Noncurrent Liabilities | Purchased Power Agreements
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	25,296,000	[3]	27,078,000	[4]
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	4,021,000		8,980,000
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	4,021,000		8,980,000
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	2,951,000		3,920,000
Estimate of Fair Value Measurement [Member] | Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	$ 2,951,000		$ 3,920,000

[1] SPS nets derivative instruments and related collateral in its balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at June 30, 2016. At June 30, 2016, derivative assets and liabilities include no obligations to return cash collateral or rights to reclaim cash collateral. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.

[2] SPS nets derivative instruments and related collateral in its balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Dec. 31, 2015. At Dec. 31, 2015, derivative assets and liabilities include no obligations to return cash collateral or rights to reclaim cash collateral. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.

[3] In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, SPS began recording several long-term PPAs at fair value due to accounting requirements related to underlying price adjustments. As these purchases are recovered through normal regulatory recovery mechanisms in the respective jurisdictions, the changes in fair value for these contracts were offset by regulatory assets and liabilities. During 2006, SPS qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.

[4] In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, SPS began recording several long-term PPAs at fair value due to accounting requirements related to underlying price adjustments. As these purchases are recovered through normal regulatory recovery mechanisms in the respective jurisdictions, the changes in fair value for these contracts were offset by regulatory assets and liabilities. During 2006, SPS qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.

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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, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Balance at beginning of period	$ 1,730,000	$ 6,457,000	$ 5,060,000	$ 15,884,000
Purchases	1,956,000	17,284,000	3,800,000	22,213,000
Settlements	(7,130,000)	(10,022,000)	(14,122,000)	(18,400,000)
Gains (losses) recognized as regulatory assets and liabilities	4,514,000	(2,256,000)	6,332,000	(8,234,000)
Balance at end of period	1,070,000	11,463,000	1,070,000	11,463,000
Transfers into Level 3	0	0	0	0
Transfers out of Level 3	$ 0	$ 0	$ 0	$ 0

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Fair Value of Financial Assets and Liabilities, Fair Value of Long-Term Debt (Details) - USD ($) $ in Thousands		Jun. 30, 2016	Dec. 31, 2015
Carrying Amount
Financial Liabilities, Balance Sheet Groupings [Abstract]
Long-term debt, including current portion	[1]	$ 1,539,177	$ 1,538,522
Fair Value
Financial Liabilities, Balance Sheet Groupings [Abstract]
Long-term debt, including current portion	[1]	$ 1,775,895	$ 1,678,673

[1] Amounts reflect the classification of debt issuance costs as a deduction from the carrying amount of the related debt. See Note 2, Accounting Pronouncements for more information on the adoption of ASU 2015-03.

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Other Income, Net (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Other Income and Expenses [Abstract]
Interest income	$ 94	$ 13	$ 179	$ 45
Other nonoperating income	298	65	247	110
Insurance policy income (expense)	0	78	0	(55)
Other income, net	$ 392	$ 156	$ 426	$ 100

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Benefit Plans and Other Postretirement Benefits (Details) $ in Thousands	1 Months Ended	3 Months Ended		6 Months Ended
	Jan. 31, 2016 USD ($) Plan	Jun. 30, 2016 USD ($)	Jun. 30, 2015 USD ($)	Jun. 30, 2016 USD ($)	Jun. 30, 2015 USD ($)
Pension Benefits
Components of Net Periodic Benefit Cost (Credit) [Abstract]
Service cost		$ 2,440	$ 2,751	$ 4,880	$ 5,503
Interest cost		5,315	5,046	10,630	10,092
Expected return on plan assets		(6,901)	(7,152)	(13,802)	(14,305)
Amortization of prior service cost (credit)		0	10	0	20
Amortization of net loss (gain)		2,997	3,772	5,994	7,544
Net periodic benefit cost (credit)		3,851	4,427	7,702	8,854
Defined Benefit Plan Credits Recognized Due To Effects of Regulation		638	686	716	1,399
Net benefit cost (credit) recognized for financial reporting		4,489	5,113	8,418	10,253
Total contributions to the pension plans during the period	$ 18,000
Postretirement Health Care Benefits
Components of Net Periodic Benefit Cost (Credit) [Abstract]
Service cost		194	238	388	477
Interest cost		455	437	910	873
Expected return on plan assets		(594)	(635)	(1,188)	(1,270)
Amortization of prior service cost (credit)		(100)	(100)	(200)	(200)
Amortization of net loss (gain)		(146)	(160)	(292)	(320)
Net periodic benefit cost (credit)		(191)	(220)	(382)	(440)
Defined Benefit Plan Credits Recognized Due To Effects of Regulation		0	0	0	0
Net benefit cost (credit) recognized for financial reporting		$ (191)	$ (220)	$ (382)	$ (440)
Xcel Energy Inc. | Pension Benefits
Components of Net Periodic Benefit Cost (Credit) [Abstract]
Total contributions to the pension plans during the period	$ 125,000
Number of Xcel Energy's pension plans to which contributions were made | Plan	4

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Other Comprehensive Income (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Accumulated other comprehensive loss at beginning of period			$ 1,807,949
Accumulated other comprehensive loss at end of period	$ 1,842,759		1,842,759
Gains and Losses on Cash Flow Hedges
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Accumulated other comprehensive loss at beginning of period	(775)	$ (947)	(817)	$ (989)
Other comprehensive income (loss) before reclassifications	0		0
Losses reclassified from net accumulated other comprehensive loss	43	43	85	85
Net current period other comprehensive income	43	43	85	85
Accumulated other comprehensive loss at end of period	(732)	$ (904)	(732)	$ (904)
Defined Benefit Pension and Postretirement Items
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Accumulated other comprehensive loss at beginning of period	(452)		(464)
Other comprehensive income (loss) before reclassifications	11		23
Losses reclassified from net accumulated other comprehensive loss	0		0
Net current period other comprehensive income	11		23
Accumulated other comprehensive loss at end of period	(441)		(441)
Total
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Accumulated other comprehensive loss at beginning of period	(1,227)		(1,281)
Other comprehensive income (loss) before reclassifications	11		23
Losses reclassified from net accumulated other comprehensive loss	43		85
Net current period other comprehensive income	54		108
Accumulated other comprehensive loss at end of period	$ (1,173)		$ (1,173)

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Other Comprehensive Income (Reclassifications from AOCI) (Details) - USD ($) $ in Thousands		3 Months Ended		6 Months Ended
		Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Total, pre-tax		$ (50,479)	$ (35,139)	$ (85,814)	$ (66,724)
Tax benefit		18,268	12,563	31,080	23,901
Gains and Losses on Cash Flow Hedges | Amounts Reclassified from Accumulated Other Comprehensive Loss
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Total, pre-tax		67	67	134	133
Tax benefit		(24)	(24)	(49)	(48)
Total, net of tax		43	43	85	85
Gains and Losses on Cash Flow Hedges | Interest Rate Derivatives | Amounts Reclassified from Accumulated Other Comprehensive Loss
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Interest charges	[1]	$ 67	$ 67	$ 134	$ 133

[1] Included in interest charges.