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 March 31, 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 May 13, 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	19
Item 4    —	Controls and Procedures	22
PART II — OTHER INFORMATION
Item 1     —	Legal Proceedings	22
Item 1A  —	Risk Factors	23
Item 4    —	Mine Safety Disclosures	23
Item 5    —	Other Information	23
Item 6    —	Exhibits	23
SIGNATURES		24
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 March 31
	2016			2015
Operating revenues	$	390,839		$	423,829
Operating expenses
Electric fuel and purchased power	213,403			245,799
Operating and maintenance expenses	64,123			73,897
Demand side management program expenses	3,377			3,669
Depreciation and amortization	40,331			35,739
Taxes (other than income taxes)	16,036			14,966
Total operating expenses	337,270			374,070
Operating income	53,569			49,759
Other income (expense), net	34			(56		)
Allowance for funds used during construction — equity	2,337			1,705
Interest charges and financing costs
Interest charges — includes other financing costs of $820 and $774, respectively	21,932			20,884
Allowance for funds used during construction — debt	(1,327		)	(1,061		)
Total interest charges and financing costs	20,605			19,823
Income before income taxes	35,335			31,585
Income taxes	12,812			11,338
Net income	$	22,523		$	20,247

See Notes to Financial Statements

3

SOUTHWESTERN PUBLIC SERVICE COMPANY

STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

(amounts in thousands)

	Three Months Ended March 31
	2016		2015
Net income	$	22,523	$	20,247
Other comprehensive income
Pension and retiree medical benefits:
Net pension and retiree medical benefits losses arising during the period,     net of tax of $7 and $0, respectively	12		—
Derivative instruments:
Reclassification of losses to net income, net of tax of     $25 and $24, respectively	42		42
Other comprehensive income	54		42
Comprehensive income	$	22,577	$	20,289

See Notes to Financial Statements

4

SOUTHWESTERN PUBLIC SERVICE COMPANY

STATEMENTS OF CASH FLOWS (UNAUDITED)

(amounts in thousands)

	Three Months Ended March 31
	2016			2015
Operating activities
Net income	$	22,523		$	20,247
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	40,660			36,310
Demand side management program amortization	418			418
Deferred income taxes	25,751			3,617
Amortization of investment tax credits	(53		)	(85		)
Allowance for equity funds used during construction	(2,337		)	(1,705		)
Net derivative losses	67			66
Changes in operating assets and liabilities:
Accounts receivable	(2,415		)	(12,719		)
Accrued unbilled revenues	1,352			26,906
Inventories	6,275			11,482
Prepayments and other	(12,428		)	(12,485		)
Accounts payable	(8,684		)	(21,160		)
Net regulatory assets and liabilities	8,361			29,566
Other current liabilities	2,289			12,521
Pension and other employee benefit obligations	(17,201		)	(10,954		)
Change in other noncurrent assets	(653		)	301
Change in other noncurrent liabilities	427			378
Net cash provided by operating activities	64,352			82,704
Investing activities
Utility capital/construction expenditures	(135,720		)	(126,622		)
Allowance for equity funds used during construction	2,337			1,705
Investments in utility money pool arrangement	—			(9,000		)
Repayments from utility money pool arrangement	—			9,000
Net cash used in investing activities	(133,383		)	(124,917		)
Financing activities
Proceeds from short-term borrowings, net	65,000			86,000
Borrowings under utility money pool arrangement	168,000			41,000
Repayments under utility money pool arrangement	(168,000		)	(57,000		)
Capital contributions from parent	16,225			—
Dividends paid to parent	(12,538		)	(27,828		)
Net cash provided by financing activities	68,687			42,172
Net change in cash and cash equivalents	(344		)	(41		)
Cash and cash equivalents at beginning of period	834			596
Cash and cash equivalents at end of period	$	490		$	555
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	(8,017	)	$	(8,870	)
Cash received (paid) for income taxes, net	405			(19,004		)
Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable	$	34,913		$	28,426

See Notes to Financial Statements

5

SOUTHWESTERN PUBLIC SERVICE COMPANY

BALANCE SHEETS (UNAUDITED)

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

	March 31, 2016			Dec. 31, 2015
Assets
Current assets
Cash and cash equivalents	$	490		$	834
Accounts receivable, net	73,460			71,166
Accounts receivable from affiliates	1,200			1,079
Accrued unbilled revenues	102,429			103,781
Inventories	31,271			37,546
Regulatory assets	27,332			31,541
Derivative instruments	8,439			12,952
Deferred income taxes	46,109			35,686
Prepaid taxes	48,253			35,666
Prepayments and other	20,360			20,520
Total current assets	359,343			350,771
Property, plant and equipment, net	4,440,167			4,348,823
Other assets
Regulatory assets	299,862			301,814
Derivative instruments	24,482			25,272
Other	4,101			3,449
Total other assets	328,445			330,535
Total assets	$	5,127,955		$	5,030,129
Liabilities and Equity
Current liabilities
Current portion of long-term debt	$	200,000		$	200,000
Short-term debt	80,000			15,000
Accounts payable	133,335			146,794
Accounts payable to affiliates	17,992			29,135
Regulatory liabilities	95,436			98,305
Taxes accrued	27,314			33,374
Accrued interest	29,619			17,781
Dividends payable	25,645			12,538
Derivative instruments	3,565			3,565
Other	31,430			35,654
Total current liabilities	644,336			592,146
Deferred credits and other liabilities
Deferred income taxes	931,686			896,430
Regulatory liabilities	235,300			229,584
Asset retirement obligations	27,588			27,233
Derivative instruments	26,187			27,078
Pension and employee benefit obligations	75,997			93,346
Other	18,137			17,841
Total deferred credits and other liabilities	1,314,895			1,291,512
Commitments and contingencies
Capitalization
Long-term debt	1,338,842			1,338,522
Common stock — 200 shares authorized of $1.00 par value; 100 shares outstanding at March 31, 2016 and Dec. 31, 2015, respectively	—			—
Additional paid in capital	1,396,223			1,371,223
Retained earnings	434,886			438,007
Accumulated other comprehensive loss	(1,227		)	(1,281		)
Total common stockholder’s equity	1,829,882			1,807,949
Total liabilities and equity	$	5,127,955		$	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 March 31, 2016, and Dec. 31, 2015; the results of its operations, including the components of net income and comprehensive income, for the three months ended March 31, 2016 and 2015; and its cash flows for the three months endedMarch 31, 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 March 31, 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 is currently evaluating the impact of adopting ASU 2016-09 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 are 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 (NAV) methodology in the fair value hierarchy. SPS implemented the guidance on Jan. 1, 2016, and the implementation did not have a material impact on its financial statements.

3. Selected Balance Sheet Data

(Thousands of Dollars)	March 31, 2016			Dec. 31, 2015
Accounts receivable, net
Accounts receivable	$	79,336		$	77,054
Less allowance for bad debts	(5,876		)	(5,888		)
	$	73,460		$	71,166

(Thousands of Dollars)	March 31, 2016		Dec. 31, 2015
Inventories
Materials and supplies	$	24,847	$	24,888
Fuel	6,424		12,658
	$	31,271	$	37,546

(Thousands of Dollars)	March 31, 2016			Dec. 31, 2015
Property, plant and equipment, net
Electric plant	$	5,989,862		$	5,933,764
Construction work in progress	305,443			236,697
Total property, plant and equipment	6,295,305			6,170,461
Less accumulated depreciation	(1,855,138		)	(1,821,638		)
	$	4,440,167		$	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 the third quarter of 2012, the Internal Revenue Service (IRS) commenced an examination of tax years 2010 and 2011, including the 2009 carryback claim. As of March 31, 2016, the IRS had proposed an adjustment to the federal tax loss carryback claims that would result in $14 million of income tax expense for the 2009 through 2011 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); 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 March 31, 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 March 31, 2016, SPS’ earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations is 2009. In February 2016, the state of Texas began an audit of years 2009 and 2010. As of March 31, 2016, the state of 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)	March 31, 2016		Dec. 31, 2015
Unrecognized tax benefit — Permanent tax positions	$	2.6	$	2.6
Unrecognized tax benefit — Temporary tax positions	21.7		22.1
Total unrecognized tax benefit	$	24.3	$	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)	March 31, 2016			Dec. 31, 2015
NOL and tax credit carryforwards	$	(5.0	)	$	(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 March 31, 2016 and Dec. 31, 2015 were not material. No amounts were accrued for penalties related to unrecognized tax benefits as of March 31, 2016 or Dec. 31, 2015.

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)

Texas 2015 Electric Rate Case — In December 2014, SPS filed a retail electric rate case in Texas seeking an overall increase in annual revenue of approximately $64.8 million, or 6.7 percent. The filing was based on a historic test year (HTY) ending June 2014, adjusted for known and measurable changes, a return on equity (ROE) of 10.25 percent, an electric rate base of approximately $1.6 billion and an equity ratio of 53.97 percent.

9

SPS requested a waiver of the PUCT post-test year adjustment rule which would allow for inclusion of $392 million (SPS total company) additional capital investment for the period July 1, 2014 through Dec. 31, 2014. In June 2015, SPS revised its requested rate increase to $42.1 million.

In December 2015, the PUCT made the following decisions:

• Disallowed SPS’ proposed adjustment to jurisdictional allocation factors to reflect Golden Spread Electric Cooperative, Inc.’s wholesale load reductions from 500 MW to 300 MW, effective June 1, 2015;

• Disallowed incentive compensation;

• Approved an equity ratio of 51.00 percent instead of the actual 53.97 percent; and

• A ROE of 9.70 percent.

The following table reflects the administrative law judges’ (ALJs’) position and PUCT’s decision:

	ALJs’ Proposal			PUCT
(Millions of Dollars)	for Decision			Decision
SPS’ revised rate request	$	42.1		$	42.1
Investment for capital expenditures — post-test year adjustments	(8.9		)	(8.9		)
Lower ROE	(6.3		)	(6.3		)
Lower capital structure	—			(3.7		)
Annual incentive compensation	(0.2		)	(0.3		)
O&M expense adjustments	(4.6		)	(4.6		)
Depreciation expense	(2.7		)	(2.7		)
Property taxes	(0.9		)	(0.9		)
Revenue adjustments	(1.1		)	(1.6		)
Wholesale load reductions	—			(11.5		)
SPP transmission expansion plan	(4.2		)	(4.2		)
Other, net	1.4			(1.2		)
Total, gross of rate case expenses	$	14.6		$	(3.8	)
Adjustment to move rate case expenses to a separate docket	(0.2		)	(0.2		)
Total, net of rate case expenses	$	14.4		$	(4.0	)
New depreciation rates	(11.2		)	(11.2		)
Earnings impact	$	3.2		$	(15.2	)

In January 2016, SPS filed its motion for rehearing on capital structure, incentive compensation and known and measurable adjustments, including wholesale load reductions and post test-year capital additions. In February 2016, the PUCT orally denied requests for rehearing. A second motion for rehearing was filed by SPS in March 2016. The PUCT took no action on the motions for rehearing and, as a result, the motions were overruled by operation of law. In April 2016, SPS filed an appeal of the PUCT’s order on rehearing.

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 HTY ended Sept. 30, 2015, a requested ROE of 10.25 percent, an electric rate base of approximately $1.7 billion, and an equity ratio of 53.97 percent. In April 2016, SPS revised its request to $68.6 million. The modification reflects actual results for the period of Oct. 1, 2015 through Dec. 31, 2015.

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

10

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.

The final rates established at the end of the case will be made effective relating back 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 decrease in base fuel revenue will be reflected in adjustments collected through the fuel and purchased power cost adjustment clause (FPPCAC). The rate filing is based on a June 30, 2015 HTY adjusted for known and measurable changes, a requested ROE of 10.25 percent, an electric jurisdictional rate base of approximately $734 million and an equity ratio of 53.97 percent.

On May 2, 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 FPPCAC. The stipulation places no restriction on when SPS may file its next base rate case.

The stipulation is subject to approval by the NMPRC. A decision by the NMPRC on the settlement and implementation of final rates is expected by August 2016.

Pending Regulatory Proceedings — Federal Energy Regulatory Commission (FERC)

SPP Open Access Transmission Tariff (OATT) Upgrade Costs — Under the SPP OATT, costs of participant-funded (or “sponsored”) transmission upgrades may be recovered, in part, from other SPP customers whose transmission service depends on capacity enabled by the sponsored 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.

On April 1, 2016, SPP filed a request with the FERC to recover the charges not billed since 2008. The SPP has indicated the investment subject to the retroactive charges could total $720 million, but the SPP filing does not quantify the charges that might be billed to individual SPP transmission customers, including SPS. SPS could also collect revenues as it has constructed a sponsored upgrade. On April 22, 2016, SPS protested the SPP filing, arguing that SPP has failed to establish that it is justified. Due to the limited information available and lack of historical precedent, the potential loss to SPS, if any, is not currently estimable. No accrual has been recorded for this matter.

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.

11

SPS had approximately 827 megawatts (MW) of capacity under long-term PPAs as of March 31, 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 EPA amended the best available retrofit technology (BART) requirements of its regional haze rules, which require the installation and operation of emission controls for industrial facilities emitting air pollutants that reduce visibility in certain national parks and wilderness areas. In its first regional haze state implementation plan (SIP), Texas identified the SPS facilities that will have to reduce sulfur dioxide (SO₂₎, nitrogen oxide (NOx) and particulate matter (PM) emissions under BART and set emissions limits for those facilities.

Texas developed a SIP that finds the Clean Air Interstate Rule (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 Cross-State Air Pollution Rule (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 in relation to the 2012 particle national ambient air quality standard (NAAQS). In March 2016, the EPA requested information under the Clean Air Act (CAA) related to EGUs at SPS’ plants. SPS replied to the request in April 2016 and 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. Xcel Energy cannot evaluate the impact of additional emission controls until the EPA concludes their evaluation of BART. The EPA is expected to issue a proposed rule in December 2016.

In December 2014, the EPA proposed to disapprove the reasonable progress portions of the Texas 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 has asked the court to stay the final rule while it is being reviewed by the court. 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 NAAQS for SO₂ — The EPA adopted a more stringent NAAQS for SO₂ in 2010. In 2013, the EPA designated areas as not attaining the revised NAAQS, which did not include any areas where SPS operates power plants.  However, many other areas of the country were unable to be classified by the EPA due to a lack of air monitors.

Following a lawsuit alleging that the EPA had not completed its area designations in the time required by the CAA and under a consent decree the EPA is requiring states to evaluate areas in three phases. The first phase includes areas near SPS’ Tolk and Harrington plants.  The Tolk and Harrington Plants utilize low sulfur coal to reduce SO₂ emissions. In February 2016, the EPA notified the Texas Commission on Environmental Quality (TCEQ) of its preliminary SO₂ designations. The EPA has proposed to designate the area near the Tolk plant as meeting the standard and the area near the Harrington plant as “unclassifiable.” If finalized as proposed, the unclassifiable areas will be monitored for three years and final designations will be made by December 2020. The EPA’s final decision is expected by July 2016. 

If an area is designated nonattainment, the respective states will need to evaluate all SO₂ sources in the area. The state would then submit an implementation plan, which would be due in 18 months, designed to achieve the NAAQS within five years. The TCEQ could require additional SO₂ controls on one or more of the units at Tolk and Harrington. SPS cannot evaluate the impacts 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 March 31, 2016			Twelve Months Ended Dec. 31, 2015
Borrowing limit	$	100		$	100
Amount outstanding at period end	—			—
Average amount outstanding	11			21
Maximum amount outstanding	88			100
Weighted average interest rate, computed on a daily basis	0.71		%	0.40		%
Weighted average interest rate at period end	N/A			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 March 31, 2016			Twelve Months Ended Dec. 31, 2015
Borrowing limit	$	400		$	400
Amount outstanding at period end	80			15
Average amount outstanding	58			100
Maximum amount outstanding	93			246
Weighted average interest rate, computed on a daily basis	0.65		%	0.46		%
Weighted average interest rate at period end	0.70			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 March 31, 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 to fulfill short-term funding needs, SPS must have a revolving credit facility in place at least equal to the amount of its commercial paper borrowing limit and cannot issue commercial paper in an aggregate amount exceeding available capacity under this credit facility. The line of credit provides short-term financing in the form of notes payable to banks, letters of credit and back-up support for commercial paper borrowings.

At March 31, 2016, SPS had the following committed credit facility available (in millions of dollars):

Credit Facility (a)		Drawn(b)		Available
$	400	$	87	$	313

^(a)  This credit facility expires in October 2019.

^(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 March 31, 2016 and Dec. 31, 2015.

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, generally referred to as financial transmission rights (FTRs). FTRs purchased from a regional transmission organization (RTO) are financial instruments that entitle or obligate the holder to monthly revenues or charges based on transmission congestion across a given transmission path. The value of an FTR is derived from, and designed to offset, the cost of energy congestion, which is caused by overall transmission load and other transmission constraints. In addition to overall transmission load, congestion is also influenced by the operating schedules of power plants and the consumption of electricity pertinent to a given transmission path. Unplanned plant outages, scheduled plant maintenance, changes in the relative costs of fuels used in generation, weather and overall changes in demand for electricity can each impact the operating schedules of the power plants on the transmission grid and the value of an FTR. The valuation process for FTRs utilizes complex iterative modeling to predict the impacts of forecasted changes in these drivers of transmission system congestion on the historical pricing of FTR purchases.

If forecasted costs of electric transmission congestion increase or decrease for a given FTR path, the value of that particular FTR instrument will likewise increase or decrease. Given the limited observability of management’s forecasts for several of the inputs to this complex valuation model - including expected plant operating schedules and retail and wholesale demand, fair value measurements for FTRs have been assigned a Level 3. 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.

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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 March 31, 2016, accumulated other comprehensive losses related to interest rate derivatives included $0.1 million of net losses expected to be reclassified into earnings during the next 12 months as the related hedged interest rate transactions impact earnings, including forecasted amounts for unsettled hedges, as applicable.

Wholesale and Commodity Trading Risk — SPS conducts various wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy and energy-related instruments. SPS’ risk management policy allows management to conduct these activities within guidelines and limitations as approved by its risk management committee, which is made up of management personnel not directly involved in the activities governed by this policy.

Commodity Derivatives — SPS enters into derivative instruments to manage variability of future cash flows from changes in commodity prices in its electric utility operations, as well as for trading purposes. This could include the purchase or sale of energy or energy-related products and FTRs.

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

(Amounts in Thousands) (a)	March 31, 2016	Dec. 31, 2015
Megawatt hours of electricity	2,691	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 months ended March 31, 2016 and 2015.

During the three months ended March 31, 2016 and 2015, changes in the fair value of FTRs resulted in pre-tax net gains of $1.3 million and pre-tax net losses of $0.8 million, respectively and were recognized as regulatory assets and liabilities. The classification as a regulatory asset or liability is based on expected recovery of FTR settlements through fuel and purchased energy cost recovery mechanisms.

FTR settlement gains of $2.1 million were recognized for the three months ended March 31, 2016, recorded to electric fuel and purchased power. For the three months ended March 31, 2015, FTR settlement losses of $0.1 million 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 months ended March 31, 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 continuously monitors the creditworthiness of the counterparties to its interest rate derivatives and commodity derivative contracts prior to settlement, and assesses each counterparty’s ability to perform on the transactions set forth in the contracts. Given this assessment, as well as an assessment of the impact of SPS’ own credit risk when determining the fair value of derivative liabilities, the impact of considering credit risk was immaterial to the fair value of unsettled commodity derivatives presented in the balance sheets.

SPS employs additional credit risk control mechanisms when appropriate, such as letters of credit, parental guarantees, standardized master netting agreements and termination provisions that allow for offsetting of positive and negative exposures. Credit exposure is monitored and, when necessary, the activity with a specific counterparty is limited until credit enhancement is provided.

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SPS’ most significant concentrations of credit risk with particular entities or industries are contracts with counterparties to its wholesale, trading and non-trading commodity and transmission activities. At March 31, 2016, seven of the most significant counterparties, comprising $43.3 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. All seven 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 March 31, 2016:

	March 31, 2016
	Fair Value						Fair Value Total		Counterparty Netting (b)
(Thousands of Dollars)	Level 1		Level 2		Level 3							Total
Current derivative assets
Other derivative instruments:
Electric commodity	$	—	$	—	$	3,118	$	3,118	$	(1,388	)	$	1,730
Total current derivative assets	$	—	$	—	$	3,118	$	3,118	$	(1,388	)	1,730
PPAs (a)												6,709
Current derivative instruments												$	8,439
Noncurrent derivative assets
PPAs (a)												$	24,482
Noncurrent derivative instruments												$	24,482
Current derivative liabilities
Other derivative instruments:
Electric commodity	$	—	$	—	$	1,388	$	1,388	$	(1,388	)	$	—
Total current derivative liabilities	$	—	$	—	$	1,388	$	1,388	$	(1,388	)	—
PPAs (a)												3,565
Current derivative instruments												$	3,565
Noncurrent derivative liabilities
PPAs (a)												$	26,187
Noncurrent derivative instruments												$	26,187

^(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 March 31, 2016. At March 31, 2016, derivative assets and liabilities include no obligations to return cash collateral or rights to reclaim cash collateral. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.

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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 months ended March 31, 2016 and 2015:

	Three Months Ended March 31
(Thousands of Dollars)	2016			2015
Balance at Jan. 1	$	5,060		$	15,884
Purchases	1,843			4,928
Settlements	(13,219		)	(8,379		)
Net transactions recorded during the period:
Gains (losses) recognized as regulatory assets and liabilities	8,046			(5,976		)
Balance at March 31	$	1,730		$	6,457

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 months ended March 31, 2016 and 2015.

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Fair Value of Long-Term Debt

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

	March 31, 2016				Dec. 31, 2015
(Thousands of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion (a)	$	1,538,842	$	1,728,470	$	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 March 31, 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 (Expense), Net

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

	Three Months Ended March 31
(Thousands of Dollars)	2016			2015
Interest income	$	85		$	32
Other nonoperating (expense) income	(51		)	45
Insurance policy expense	—			(133		)
Other income (expense), net	$	34		$	(56	)

10. Benefit Plans and Other Postretirement Benefits

Components of Net Periodic Benefit Cost (Credit)

	Three Months Ended March 31
	2016			2015			2016			2015
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Service cost	$	2,440		$	2,752		$	194		$	239
Interest cost	5,315			5,046			455			436
Expected return on plan assets	(6,901		)	(7,153		)	(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	78			713			—			—
Net benefit cost (credit) recognized for financial reporting	$	3,929		$	5,140		$	(191	)	$	(220	)

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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11. Other Comprehensive Income

Changes in accumulated other comprehensive loss, net of tax, for the three months ended March 31, 2016 and 2015 were as follows:

	Three Months Ended March 31, 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	—			12			12
Losses reclassified from net accumulated other comprehensive loss	42			—			42
Net current period other comprehensive loss	42			12			54
Accumulated other comprehensive loss at March 31	$	(775	)	$	(452	)	$	(1,227	)

	Three Months Ended March 31, 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	42
Net current period other comprehensive loss	42
Accumulated other comprehensive loss at March 31	$	(947	)

Reclassifications from accumulated other comprehensive loss for the three months ended March 31, 2016 and 2015 were as follows:

	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Three Months Ended March 31, 2016				Three Months Ended March 31, 2015
Losses on cash flow hedges:
Interest rate derivatives	$	67		(a)	$	66		(a)
Total, pre-tax	67				66
Tax benefit	(25		)		(24		)
Total amounts reclassified, net of tax	$	42			$	42

^(a)  Included in interest charges.

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

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

Financial Review

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

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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), 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 $22.5 million for the first quarter of 2016, compared with net income of approximately $20.2 million for the same period in 2015. Lower O&M expenses were offset by higher 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:

	Three Months Ended March 31
(Millions of Dollars)	2016			2015
Electric revenues	$	391		$	424
Electric fuel and purchased power	(213		)	(246		)
Electric margin	$	178		$	178

The following tables summarize the components of the changes in electric revenues and electric margin for the first quarter of 2016:

Electric Revenues

(Millions of Dollars)	2016 vs. 2015
Fuel and purchased power cost recovery	$	(22	)
Trading	(10		)
Estimated impact of weather	(4		)
Firm wholesale	(3		)
Transmission revenue	6
Total decrease in electric revenues	$	(33	)

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Electric Margin

(Millions of Dollars)	2016 vs. 2015
Fuel handling	$	5
Estimated impact of weather	(4		)
Firm wholesale	(3		)
Other, net	2
Total change in electric margin	$	—

Non-Fuel Operating Expense and Other Items

O&M Expenses — O&M expenses decreased $9.8 million, or 13.2 percent, for the first quarter of 2016. The decrease was mainly due to the timing of plant outages and lower employee benefit costs.

Depreciation and Amortization — Depreciation and amortization increased $4.6 million, or 12.8 percent, for the first quarter of 2016. The increase is primarily due to new capital investments.

Taxes (Other Than Income Taxes) — Taxes (other than income taxes) increased $1.1 million, or 7.1 percent, for the first quarter of 2016. The increase is primarily due to an increase in property taxes.

AFUDC —AFUDC increased $0.9 million for the first quarter of 2016. The increase is primarily due to the increase of transmission facilities construction.

Interest Charges — Interest charges increased $1.0 million, or 5.0 percent, for the first quarter of 2016. The increase is primarily due to higher long-term debt levels, partially offset by lower interest rates.

Income Taxes — Income tax expense increased $1.5 million for the first quarter of 2016. The increase in income tax expense is primarily due to higher pretax earnings in 2016. The ETR was 36.3 percent for the first quarter of 2016, compared with 35.9 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 KV Transmission Line— In June 2015, SPS filed a CCN with the PUCT for the Yoakum County to Texas/New Mexico State line portion of this 345 KV line project and the PUCT approved this CCN in March 2016. This line will connect the TUCO substation near Lubbock, Texas with the Yoakum County substation, continuing on to the Hobbs Plant substation near Hobbs, New Mexico. CCNs for the TUCO to Yoakum County substation segment and for the Texas/New Mexico state line to Hobbs Plant segment are planned to be filed later in 2016. The estimated project cost is $242 million. This line is scheduled to be in service in 2020.

Hobbs Plant Substation to China Draw Substation 345 KV Transmission Line — The Hobbs Plant to China Draw transmission line will connect the Hobbs Plant substation to the China Draw substation near Malaga, N.M. with terminations at a proposed Kiowa substation near Carlsbad, N.M. and at the North Loving substation, near Loving, N.M. In May 2016, SPS filed a CCN for this line in New Mexico. 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 may 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.

Summary of Recent Federal Regulatory Developments

The FERC has jurisdiction over rates for electric transmission service in interstate commerce and electricity sold at wholesale, asset transactions and mergers, accounting practices and certain other activities of SPS, including enforcement of North American Electric Reliability Corporation mandatory electric reliability standards. State and local agencies have jurisdiction over many of SPS’ activities, including regulation of retail rates and environmental matters. See additional discussion in the summary of recent federal regulatory developments and public utility regulation sections of the SPS Annual Report on Form 10-K for the year ended Dec. 31, 2015. In addition to the matters discussed below, see Note 5 to the financial statements for a discussion of other regulatory matters.

FERC Order, New ROE Policy — In June 2014, the FERC adopted a new two-step ROE methodology for electric utilities. In March, 2015, FERC upheld the new ROE methodology and denied rehearing. The issue of how to apply the new FERC ROE methodology is being contested in various complaint proceedings. As part of a global settlement approved by the FERC in October 2015, three ROE complaints against SPS were resolved. FERC is not expected to issue orders in any of the litigated ROE complaint proceedings until 2016 or 2017.

SPS Asset Transfer to XEST - In October 2015, SPS submitted filings to the PUCT, NMPRC and Kansas Corporation Commission (KCC) seeking approval to transfer ownership of SPS’ 345kV transmission assets in Kansas and Oklahoma to XEST at net book value of approximately $103 million. After the proposed asset transfer, the transmission facilities would remain subject to SPP functional control, with revenue requirements recovered through the SPP Tariff. SPS and XEST also proposed to enter into a transmission operation and maintenance agreement (O&M Agreement) under which SPS would operate and maintain the transferred facilities and be reimbursed for providing those services to XEST at cost. Key developments related to the filings are as follows:

• The KCC is expected to issue a decision within 10 months of the October filing;

• The hearings in the NMPRC proceedings are scheduled for August 2016 with a decision expected several months later;

• The hearings in the PUCT proceedings are scheduled for October 2016 with a decision expected several months later;

• In December of 2015, Oklahoma Corporation Commission Staff declined jurisdiction in response to SPS;

• Requests for FERC approval of the asset transfer and O&M Agreement were submitted in January 2016, and requested FERC action by June 30, 2016. Golden Spread Electric Cooperative, Inc. (Golden Spread) protested the FERC asset transfer application; and

• Based on the procedural schedules, and assuming receipt of, the required regulatory approvals, SPS expects the proposed asset transfer would take place no earlier than late 2016 or early 2017.

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 2015 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 December 2015, the FERC required SPS to submit additional information regarding its formula rate changes. In April 2016, FERC accepted the SPS formula rate changes, subject to a compliance filing.

21

SPP and MISO Complaints Regarding RTO Joint Operating Agreement (JOA) -SPP and MISO were involved in a long-running dispute regarding the interpretation of their JOA, which is intended to coordinate RTO operations along the MISO/SPP system boundary. SPP and MISO disagreed over MISO’s authority to transmit power between the traditional MISO region in the Midwest and the Entergy system. Several cases were filed with the FERC by MISO and SPP between 2011 and 2014. In June 2014, the FERC set the issues for settlement judge and hearing procedures.

In January 2016, the FERC approved a settlement between SPP, MISO and other parties that resolves various disputed matters and provide a defined settlement compensation plan by MISO to SPP. MISO will pay SPP $16 million for the two-year retroactive period (February 2014 to January 2016) and $16 million annually prospectively starting Feb. 1, 2016, subject to a true-up. In January 2016, SPP filed a proposal regarding distribution of the MISO revenues to SPP members, including SPS. In March 2016, the FERC issued an order rejecting one component of the SPP filing, accepting the remainder of the SPP tariff proposal subject to refund, and setting the filing for settlement judge or hearing procedures. The JOA revenue allocated to SPS under the filed SPP proposal was not expected to be material. Separate settlement discussions are ongoing regarding the April 2014 MISO tariff change filing to recover SPP JOA charges in MISO rates.

Item 4 — CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

SPS maintains a set of disclosure controls and procedures designed to ensure that information required to be disclosed in the reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized, and reported within the time periods specified in SEC rules and forms.  In addition, the disclosure controls and procedures ensure that information required to be disclosed is accumulated and communicated to management, including the chief executive officer (CEO) and chief financial officer (CFO), allowing timely decisions regarding required disclosure.  As of March 31, 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 believe the implementation of the general ledger modules, which occurred during the period ended March 31, 2016, materially affected its internal control over financial reporting. SPS also does not expect the implementation of the additional modules to materially affect its internal control over financial reporting.

No other 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.

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.

22

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

3.01*	Amended and Restated Articles of Incorporation of SPS dated Sept. 30, 1997 (Exhibit 3(a)(2) to Form 10-K (file no. 001-03789) dated March 3, 1998).
3.02*	By-Laws of SPS as Amended and Restated on Sept. 26, 2013. (Exhibit 3.02 to Form 10-Q/A for the quarter ended Sept. 30, 2013 (file no. 001-03789)).
31.01	Principal Executive Officer’s certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.02	Principal Financial Officer’s certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.01	Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.01	Statement pursuant to Private Securities Litigation Reform Act of 1995.
101	The following materials from SPS’ Quarterly Report on Form 10-Q for the quarter ended March 31, 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.

23

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
May 13, 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)

24

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: May 13, 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: May 13, 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 March 31, 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: May 13, 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	3 Months Ended
	Mar. 31, 2016	May. 13, 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
Document Type	10-Q
Document Period End Date	Mar. 31, 2016
Document Fiscal Year Focus	2016
Document Fiscal Period Focus	Q1
Amendment Flag	false
Entity Common Stock, Shares Outstanding		100

XML

STATEMENTS OF INCOME (UNAUDITED) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Income Statement [Abstract]
Operating revenues	$ 390,839	$ 423,829
Operating expenses
Electric fuel and purchased power	213,403	245,799
Operating and maintenance expenses	64,123	73,897
Demand side management program expenses	3,377	3,669
Depreciation and amortization	40,331	35,739
Taxes (other than income taxes)	16,036	14,966
Total operating expenses	337,270	374,070
Operating income	53,569	49,759
Other income (expense), net	34	(56)
Allowance for funds used during construction — equity	2,337	1,705
Interest charges and financing costs
Interest charges — includes other financing costs of $820 and $774, respectively	21,932	20,884
Public Utilities, Allowance For Funds Used During Construction, Capitalized Cost Of Debt	(1,327)	(1,061)
Total interest charges and financing costs	20,605	19,823
Income before income taxes	35,335	31,585
Income taxes	12,812	11,338
Net income	$ 22,523	$ 20,247

XML

STATEMENTS OF INCOME (UNAUDITED) (Parenthetical) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Interest charges and financing costs
Other financing costs	$ 820	$ 774

XML

STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Comprehensive income:
Net income	$ 22,523	$ 20,247
Net pension and retiree medical benefits losses arising during the period, net of tax of $7 and $0, respectively	12	0
Derivative instruments:
Reclassification of losses to net income, net of tax of $25 and $24, respectively	42	42
Other comprehensive income	54	42
Comprehensive income	$ 22,577	$ 20,289

XML

STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED) (Parenthetical) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Derivative instruments:
Reclassification of losses to net income, tax	$ 25	$ 24
Other Comprehensive (Income) Loss, Amortization Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Prior Service Cost (Credit), Tax	$ 7	$ 0

XML

STATEMENTS OF CASH FLOWS (UNAUDITED) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Operating activities
Net income	$ 22,523	$ 20,247
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	40,660	36,310
Demand side management program amortization	418	418
Deferred income taxes	25,751	3,617
Amortization of Investment Tax Credits	(53)	(85)
Allowance for equity funds used during construction	(2,337)	(1,705)
Net derivative losses	67	66
Changes in operating assets and liabilities:
Accounts receivable	(2,415)	(12,719)
Accrued unbilled revenues	1,352	26,906
Inventories	6,275	11,482
Prepayments and other	(12,428)	(12,485)
Accounts payable	(8,684)	(21,160)
Net regulatory assets and liabilities	8,361	29,566
Other current liabilities	2,289	12,521
Pension and other employee benefit obligations	(17,201)	(10,954)
Change in other noncurrent assets	(653)	301
Change in other noncurrent liabilities	427	378
Net cash provided by operating activities	64,352	82,704
Investing activities
Utility capital/construction expenditures	(135,720)	(126,622)
Allowance for equity funds used during construction	2,337	1,705
Investments in utility money pool arrangement	0	(9,000)
Repayments from utility money pool arrangement	0	9,000
Net cash used in investing activities	(133,383)	(124,917)
Financing activities
Proceeds from short-term borrowings, net	65,000	86,000
Borrowings under utility money pool arrangement	168,000	41,000
Repayments under utility money pool arrangement	(168,000)	(57,000)
Capital contributions from parent	16,225	0
Dividends paid to parent	(12,538)	(27,828)
Net cash provided by financing activities	68,687	42,172
Net change in cash and cash equivalents	(344)	(41)
Cash and cash equivalents at beginning of period	834
Cash and cash equivalents at end of period	490
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	(8,017)	(8,870)
Cash received (paid) for income taxes, net	405	(19,004)
Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable	$ 34,913	$ 28,426

XML

BALANCE SHEETS (UNAUDITED) - USD ($) $ in Thousands	Mar. 31, 2016	Dec. 31, 2015
Current assets
Cash and cash equivalents	$ 490	$ 834
Accounts receivable, net	73,460	71,166
Accounts receivable from affiliates	1,200	1,079
Accrued unbilled revenues	102,429	103,781
Inventories	31,271	37,546
Regulatory assets	27,332	31,541
Derivative instruments	8,439	12,952
Deferred income taxes	46,109	35,686
Prepaid taxes	48,253	35,666
Prepayments and other	20,360	20,520
Total current assets	359,343	350,771
Property, plant and equipment, net	4,440,167	4,348,823
Other assets
Regulatory assets	299,862	301,814
Derivative instruments	24,482	25,272
Other	4,101	3,449
Total other assets	328,445	330,535
Total assets	5,127,955	5,030,129
Current liabilities
Current portion of long-term debt	200,000	200,000
Short-term debt	80,000	15,000
Accounts payable	133,335	146,794
Accounts payable to affiliates	17,992	29,135
Regulatory liabilities	95,436	98,305
Taxes accrued	27,314	33,374
Accrued interest	29,619	17,781
Dividends payable	25,645	12,538
Derivative instruments	3,565	3,565
Other	31,430	35,654
Total current liabilities	644,336	592,146
Deferred credits and other liabilities
Deferred income taxes	931,686	896,430
Regulatory liabilities	235,300	229,584
Asset retirement obligations	27,588	27,233
Derivative instruments	26,187	27,078
Pension and employee benefit obligations	75,997	93,346
Other	18,137	17,841
Total deferred credits and other liabilities	$ 1,314,895	$ 1,291,512
Commitments and contingencies
Capitalization
Long-term debt	$ 1,338,842	$ 1,338,522
Common stock — 200 shares authorized of $1.00 par value; 100 shares outstanding at March 31, 2016 and Dec. 31, 2015, respectively	0	0
Additional paid in capital	1,396,223	1,371,223
Retained earnings	434,886	438,007
Accumulated other comprehensive loss	(1,227)	(1,281)
Total common stockholder’s equity	1,829,882	1,807,949
Total liabilities and equity	$ 5,127,955	$ 5,030,129

XML

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

XML

Management's Opinion

3 Months Ended

Mar. 31, 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 March 31, 2016, and Dec. 31, 2015; the results of its operations, including the components of net income and comprehensive income, for the three months ended March 31, 2016 and 2015; and its cash flows for the three months endedMarch 31, 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 March 31, 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

3 Months Ended

Mar. 31, 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

3 Months Ended

Mar. 31, 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 is currently evaluating the impact of adopting ASU 2016-09 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 are 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 (NAV) methodology in the fair value hierarchy. SPS implemented the guidance on Jan. 1, 2016, and the implementation did not have a material impact on its financial statements.

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Selected Balance Sheet Data

3 Months Ended

Mar. 31, 2016

Balance Sheet Related Disclosures [Abstract]

Selected Balance Sheet Data

Selected Balance Sheet Data

(Thousands of Dollars)	March 31, 2016			Dec. 31, 2015
Accounts receivable, net
Accounts receivable	$	79,336		$	77,054
Less allowance for bad debts	(5,876		)	(5,888		)
	$	73,460		$	71,166

(Thousands of Dollars)	March 31, 2016		Dec. 31, 2015
Inventories
Materials and supplies	$	24,847	$	24,888
Fuel	6,424		12,658
	$	31,271	$	37,546

(Thousands of Dollars)	March 31, 2016			Dec. 31, 2015
Property, plant and equipment, net
Electric plant	$	5,989,862		$	5,933,764
Construction work in progress	305,443			236,697
Total property, plant and equipment	6,295,305			6,170,461
Less accumulated depreciation	(1,855,138		)	(1,821,638		)
	$	4,440,167		$	4,348,823

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Income Taxes

3 Months Ended

Mar. 31, 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 the third quarter of 2012, the Internal Revenue Service (IRS) commenced an examination of tax years 2010 and 2011, including the 2009 carryback claim. As of March 31, 2016, the IRS had proposed an adjustment to the federal tax loss carryback claims that would result in $14 million of income tax expense for the 2009 through 2011 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); 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 March 31, 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 March 31, 2016, SPS’ earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations is 2009. In February 2016, the state of Texas began an audit of years 2009 and 2010. As of March 31, 2016, the state of 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)	March 31, 2016		Dec. 31, 2015
Unrecognized tax benefit — Permanent tax positions	$	2.6	$	2.6
Unrecognized tax benefit — Temporary tax positions	21.7		22.1
Total unrecognized tax benefit	$	24.3	$	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)	March 31, 2016			Dec. 31, 2015
NOL and tax credit carryforwards	$	(5.0	)	$	(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 March 31, 2016 and Dec. 31, 2015 were not material. No amounts were accrued for penalties related to unrecognized tax benefits as of March 31, 2016 or Dec. 31, 2015.

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Rate Matters

3 Months Ended

Mar. 31, 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)

Texas 2015 Electric Rate Case — In December 2014, SPS filed a retail electric rate case in Texas seeking an overall increase in annual revenue of approximately $64.8 million, or 6.7 percent. The filing was based on a historic test year (HTY) ending June 2014, adjusted for known and measurable changes, a return on equity (ROE) of 10.25 percent, an electric rate base of approximately $1.6 billion and an equity ratio of 53.97 percent.

SPS requested a waiver of the PUCT post-test year adjustment rule which would allow for inclusion of $392 million (SPS total company) additional capital investment for the period July 1, 2014 through Dec. 31, 2014. In June 2015, SPS revised its requested rate increase to $42.1 million.

In December 2015, the PUCT made the following decisions:

• Disallowed SPS’ proposed adjustment to jurisdictional allocation factors to reflect Golden Spread Electric Cooperative, Inc.’s wholesale load reductions from 500 MW to 300 MW, effective June 1, 2015;

• Disallowed incentive compensation;

• Approved an equity ratio of 51.00 percent instead of the actual 53.97 percent; and

• A ROE of 9.70 percent.

The following table reflects the administrative law judges’ (ALJs’) position and PUCT’s decision:

	ALJs’ Proposal			PUCT
(Millions of Dollars)	for Decision			Decision
SPS’ revised rate request	$	42.1		$	42.1
Investment for capital expenditures — post-test year adjustments	(8.9		)	(8.9		)
Lower ROE	(6.3		)	(6.3		)
Lower capital structure	—			(3.7		)
Annual incentive compensation	(0.2		)	(0.3		)
O&M expense adjustments	(4.6		)	(4.6		)
Depreciation expense	(2.7		)	(2.7		)
Property taxes	(0.9		)	(0.9		)
Revenue adjustments	(1.1		)	(1.6		)
Wholesale load reductions	—			(11.5		)
SPP transmission expansion plan	(4.2		)	(4.2		)
Other, net	1.4			(1.2		)
Total, gross of rate case expenses	$	14.6		$	(3.8	)
Adjustment to move rate case expenses to a separate docket	(0.2		)	(0.2		)
Total, net of rate case expenses	$	14.4		$	(4.0	)
New depreciation rates	(11.2		)	(11.2		)
Earnings impact	$	3.2		$	(15.2	)

In January 2016, SPS filed its motion for rehearing on capital structure, incentive compensation and known and measurable adjustments, including wholesale load reductions and post test-year capital additions. In February 2016, the PUCT orally denied requests for rehearing. A second motion for rehearing was filed by SPS in March 2016. The PUCT took no action on the motions for rehearing and, as a result, the motions were overruled by operation of law. In April 2016, SPS filed an appeal of the PUCT’s order on rehearing.

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 HTY ended Sept. 30, 2015, a requested ROE of 10.25 percent, an electric rate base of approximately $1.7 billion, and an equity ratio of 53.97 percent. In April 2016, SPS revised its request to $68.6 million. The modification reflects actual results for the period of Oct. 1, 2015 through Dec. 31, 2015.

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.

The final rates established at the end of the case will be made effective relating back 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 decrease in base fuel revenue will be reflected in adjustments collected through the fuel and purchased power cost adjustment clause (FPPCAC). The rate filing is based on a June 30, 2015 HTY adjusted for known and measurable changes, a requested ROE of 10.25 percent, an electric jurisdictional rate base of approximately $734 million and an equity ratio of 53.97 percent.

On May 2, 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 FPPCAC. The stipulation places no restriction on when SPS may file its next base rate case.

The stipulation is subject to approval by the NMPRC. A decision by the NMPRC on the settlement and implementation of final rates is expected by August 2016.

Pending Regulatory Proceedings — Federal Energy Regulatory Commission (FERC)

SPP Open Access Transmission Tariff (OATT) Upgrade Costs — Under the SPP OATT, costs of participant-funded (or “sponsored”) transmission upgrades may be recovered, in part, from other SPP customers whose transmission service depends on capacity enabled by the sponsored 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.

On April 1, 2016, SPP filed a request with the FERC to recover the charges not billed since 2008. The SPP has indicated the investment subject to the retroactive charges could total $720 million, but the SPP filing does not quantify the charges that might be billed to individual SPP transmission customers, including SPS. SPS could also collect revenues as it has constructed a sponsored upgrade. On April 22, 2016, SPS protested the SPP filing, arguing that SPP has failed to establish that it is justified. Due to the limited information available and lack of historical precedent, the potential loss to SPS, if any, is not currently estimable. No accrual has been recorded for this matter.

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Commitments and Contingencies

3 Months Ended

Mar. 31, 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 March 31, 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 EPA amended the best available retrofit technology (BART) requirements of its regional haze rules, which require the installation and operation of emission controls for industrial facilities emitting air pollutants that reduce visibility in certain national parks and wilderness areas. In its first regional haze state implementation plan (SIP), Texas identified the SPS facilities that will have to reduce sulfur dioxide (SO₂₎, nitrogen oxide (NOx) and particulate matter (PM) emissions under BART and set emissions limits for those facilities.

Texas developed a SIP that finds the Clean Air Interstate Rule (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 Cross-State Air Pollution Rule (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 in relation to the 2012 particle national ambient air quality standard (NAAQS). In March 2016, the EPA requested information under the Clean Air Act (CAA) related to EGUs at SPS’ plants. SPS replied to the request in April 2016 and 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. Xcel Energy cannot evaluate the impact of additional emission controls until the EPA concludes their evaluation of BART. The EPA is expected to issue a proposed rule in December 2016.

In December 2014, the EPA proposed to disapprove the reasonable progress portions of the Texas 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 has asked the court to stay the final rule while it is being reviewed by the court. 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 NAAQS for SO₂ — The EPA adopted a more stringent NAAQS for SO₂ in 2010. In 2013, the EPA designated areas as not attaining the revised NAAQS, which did not include any areas where SPS operates power plants.  However, many other areas of the country were unable to be classified by the EPA due to a lack of air monitors.

Following a lawsuit alleging that the EPA had not completed its area designations in the time required by the CAA and under a consent decree the EPA is requiring states to evaluate areas in three phases. The first phase includes areas near SPS’ Tolk and Harrington plants.  The Tolk and Harrington Plants utilize low sulfur coal to reduce SO₂ emissions. In February 2016, the EPA notified the Texas Commission on Environmental Quality (TCEQ) of its preliminary SO₂ designations. The EPA has proposed to designate the area near the Tolk plant as meeting the standard and the area near the Harrington plant as “unclassifiable.” If finalized as proposed, the unclassifiable areas will be monitored for three years and final designations will be made by December 2020. The EPA’s final decision is expected by July 2016. 

If an area is designated nonattainment, the respective states will need to evaluate all SO₂ sources in the area. The state would then submit an implementation plan, which would be due in 18 months, designed to achieve the NAAQS within five years. The TCEQ could require additional SO₂ controls on one or more of the units at Tolk and Harrington. SPS cannot evaluate the impacts 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

3 Months Ended

Mar. 31, 2016

Debt Disclosure [Abstract]

Borrowings and Other Financing Instruments

Borrowings and Other Financing Instruments

Short-Term Borrowings

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

(Amounts in Millions, Except Interest Rates)	Three Months Ended March 31, 2016			Twelve Months Ended Dec. 31, 2015
Borrowing limit	$	100		$	100
Amount outstanding at period end	—			—
Average amount outstanding	11			21
Maximum amount outstanding	88			100
Weighted average interest rate, computed on a daily basis	0.71		%	0.40		%
Weighted average interest rate at period end	N/A			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 March 31, 2016			Twelve Months Ended Dec. 31, 2015
Borrowing limit	$	400		$	400
Amount outstanding at period end	80			15
Average amount outstanding	58			100
Maximum amount outstanding	93			246
Weighted average interest rate, computed on a daily basis	0.65		%	0.46		%
Weighted average interest rate at period end	0.70			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 March 31, 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 to fulfill short-term funding needs, SPS must have a revolving credit facility in place at least equal to the amount of its commercial paper borrowing limit and cannot issue commercial paper in an aggregate amount exceeding available capacity under this credit facility. The line of credit provides short-term financing in the form of notes payable to banks, letters of credit and back-up support for commercial paper borrowings.

At March 31, 2016, SPS had the following committed credit facility available (in millions of dollars):

Credit Facility (a)		Drawn(b)		Available
$	400	$	87	$	313

^(a)  This credit facility expires in October 2019.

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

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

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Fair Value of Financial Assets and Liabilities

3 Months Ended

Mar. 31, 2016

Fair Value Disclosures [Abstract]

Fair Value of Financial Assets and Liabilities

Fair Value of Financial Assets and Liabilities

Fair Value Measurements

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

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

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

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

Specific valuation methods include the following:

Cash equivalents— The fair values of cash equivalents are generally based on cost plus accrued interest; money market funds are measured using quoted 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, generally referred to as financial transmission rights (FTRs). FTRs purchased from a regional transmission organization (RTO) are financial instruments that entitle or obligate the holder to monthly revenues or charges based on transmission congestion across a given transmission path. The value of an FTR is derived from, and designed to offset, the cost of energy congestion, which is caused by overall transmission load and other transmission constraints. In addition to overall transmission load, congestion is also influenced by the operating schedules of power plants and the consumption of electricity pertinent to a given transmission path. Unplanned plant outages, scheduled plant maintenance, changes in the relative costs of fuels used in generation, weather and overall changes in demand for electricity can each impact the operating schedules of the power plants on the transmission grid and the value of an FTR. The valuation process for FTRs utilizes complex iterative modeling to predict the impacts of forecasted changes in these drivers of transmission system congestion on the historical pricing of FTR purchases.

If forecasted costs of electric transmission congestion increase or decrease for a given FTR path, the value of that particular FTR instrument will likewise increase or decrease. Given the limited observability of management’s forecasts for several of the inputs to this complex valuation model - including expected plant operating schedules and retail and wholesale demand, fair value measurements for FTRs have been assigned a Level 3. 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 March 31, 2016, accumulated other comprehensive losses related to interest rate derivatives included $0.1 million of net losses expected to be reclassified into earnings during the next 12 months as the related hedged interest rate transactions impact earnings, including forecasted amounts for unsettled hedges, as applicable.

Wholesale and Commodity Trading Risk — SPS conducts various wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy and energy-related instruments. SPS’ risk management policy allows management to conduct these activities within guidelines and limitations as approved by its risk management committee, which is made up of management personnel not directly involved in the activities governed by this policy.

Commodity Derivatives — SPS enters into derivative instruments to manage variability of future cash flows from changes in commodity prices in its electric utility operations, as well as for trading purposes. This could include the purchase or sale of energy or energy-related products and FTRs.

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

(Amounts in Thousands) (a)	March 31, 2016	Dec. 31, 2015
Megawatt hours of electricity	2,691	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 months ended March 31, 2016 and 2015.

During the three months ended March 31, 2016 and 2015, changes in the fair value of FTRs resulted in pre-tax net gains of $1.3 million and pre-tax net losses of $0.8 million, respectively and were recognized as regulatory assets and liabilities. The classification as a regulatory asset or liability is based on expected recovery of FTR settlements through fuel and purchased energy cost recovery mechanisms.

FTR settlement gains of $2.1 million were recognized for the three months ended March 31, 2016, recorded to electric fuel and purchased power. For the three months ended March 31, 2015, FTR settlement losses of $0.1 million 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 months ended March 31, 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 continuously monitors the creditworthiness of the counterparties to its interest rate derivatives and commodity derivative contracts prior to settlement, and assesses each counterparty’s ability to perform on the transactions set forth in the contracts. Given this assessment, as well as an assessment of the impact of SPS’ own credit risk when determining the fair value of derivative liabilities, the impact of considering credit risk was immaterial to the fair value of unsettled commodity derivatives presented in the balance sheets.

SPS employs additional credit risk control mechanisms when appropriate, such as letters of credit, parental guarantees, standardized master netting agreements and termination provisions that allow for offsetting of positive and negative exposures. Credit exposure is monitored and, when necessary, the activity with a specific counterparty is limited until credit enhancement is provided.

SPS’ most significant concentrations of credit risk with particular entities or industries are contracts with counterparties to its wholesale, trading and non-trading commodity and transmission activities. At March 31, 2016, seven of the most significant counterparties, comprising $43.3 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. All seven 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 March 31, 2016:

	March 31, 2016
	Fair Value						Fair Value Total		Counterparty Netting (b)
(Thousands of Dollars)	Level 1		Level 2		Level 3							Total
Current derivative assets
Other derivative instruments:
Electric commodity	$	—	$	—	$	3,118	$	3,118	$	(1,388	)	$	1,730
Total current derivative assets	$	—	$	—	$	3,118	$	3,118	$	(1,388	)	1,730
PPAs (a)												6,709
Current derivative instruments												$	8,439
Noncurrent derivative assets
PPAs (a)												$	24,482
Noncurrent derivative instruments												$	24,482
Current derivative liabilities
Other derivative instruments:
Electric commodity	$	—	$	—	$	1,388	$	1,388	$	(1,388	)	$	—
Total current derivative liabilities	$	—	$	—	$	1,388	$	1,388	$	(1,388	)	—
PPAs (a)												3,565
Current derivative instruments												$	3,565
Noncurrent derivative liabilities
PPAs (a)												$	26,187
Noncurrent derivative instruments												$	26,187

^(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 March 31, 2016. At March 31, 2016, derivative assets and liabilities include no obligations to return cash collateral or rights to reclaim cash collateral. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.

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

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

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

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

The following table presents the changes in Level 3 commodity derivatives for the three months ended March 31, 2016 and 2015:

	Three Months Ended March 31
(Thousands of Dollars)	2016			2015
Balance at Jan. 1	$	5,060		$	15,884
Purchases	1,843			4,928
Settlements	(13,219		)	(8,379		)
Net transactions recorded during the period:
Gains (losses) recognized as regulatory assets and liabilities	8,046			(5,976		)
Balance at March 31	$	1,730		$	6,457

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 months ended March 31, 2016 and 2015.

Fair Value of Long-Term Debt

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

	March 31, 2016				Dec. 31, 2015
(Thousands of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion (a)	$	1,538,842	$	1,728,470	$	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 March 31, 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 (Expense), Net

3 Months Ended

Mar. 31, 2016

Other Income and Expenses [Abstract]

Other Income (Expense), Net

Other Income (Expense), Net

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

	Three Months Ended March 31
(Thousands of Dollars)	2016			2015
Interest income	$	85		$	32
Other nonoperating (expense) income	(51		)	45
Insurance policy expense	—			(133		)
Other income (expense), net	$	34		$	(56	)

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Benefit Plans and Other Postretirement Benefits

3 Months Ended

Mar. 31, 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 March 31
	2016			2015			2016			2015
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Service cost	$	2,440		$	2,752		$	194		$	239
Interest cost	5,315			5,046			455			436
Expected return on plan assets	(6,901		)	(7,153		)	(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	78			713			—			—
Net benefit cost (credit) recognized for financial reporting	$	3,929		$	5,140		$	(191	)	$	(220	)

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

3 Months Ended

Mar. 31, 2016

Stockholders' Equity Note [Abstract]

Other Comprehensive Income

Other Comprehensive Income

Changes in accumulated other comprehensive loss, net of tax, for the three months ended March 31, 2016 and 2015 were as follows:

	Three Months Ended March 31, 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	—			12			12
Losses reclassified from net accumulated other comprehensive loss	42			—			42
Net current period other comprehensive loss	42			12			54
Accumulated other comprehensive loss at March 31	$	(775	)	$	(452	)	$	(1,227	)

	Three Months Ended March 31, 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	42
Net current period other comprehensive loss	42
Accumulated other comprehensive loss at March 31	$	(947	)

Reclassifications from accumulated other comprehensive loss for the three months ended March 31, 2016 and 2015 were as follows:

	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Three Months Ended March 31, 2016				Three Months Ended March 31, 2015
Losses on cash flow hedges:
Interest rate derivatives	$	67		(a)	$	66		(a)
Total, pre-tax	67				66
Tax benefit	(25		)		(24		)
Total amounts reclassified, net of tax	$	42			$	42

^(a)  Included in interest charges.

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Selected Balance Sheet Data (Tables)

3 Months Ended

Mar. 31, 2016

Balance Sheet Related Disclosures [Abstract]

Accounts Receivable, Net

(Thousands of Dollars)	March 31, 2016			Dec. 31, 2015
Accounts receivable, net
Accounts receivable	$	79,336		$	77,054
Less allowance for bad debts	(5,876		)	(5,888		)
	$	73,460		$	71,166

Inventories

(Thousands of Dollars)	March 31, 2016		Dec. 31, 2015
Inventories
Materials and supplies	$	24,847	$	24,888
Fuel	6,424		12,658
	$	31,271	$	37,546

Property, Plant and Equipment, Net

(Thousands of Dollars)	March 31, 2016			Dec. 31, 2015
Property, plant and equipment, net
Electric plant	$	5,989,862		$	5,933,764
Construction work in progress	305,443			236,697
Total property, plant and equipment	6,295,305			6,170,461
Less accumulated depreciation	(1,855,138		)	(1,821,638		)
	$	4,440,167		$	4,348,823

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Income Taxes (Tables)

3 Months Ended

Mar. 31, 2016

Income Tax Disclosure [Abstract]

Reconciliation of Unrecognized Tax Benefits

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

(Millions of Dollars)	March 31, 2016		Dec. 31, 2015
Unrecognized tax benefit — Permanent tax positions	$	2.6	$	2.6
Unrecognized tax benefit — Temporary tax positions	21.7		22.1
Total unrecognized tax benefit	$	24.3	$	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)	March 31, 2016			Dec. 31, 2015
NOL and tax credit carryforwards	$	(5.0	)	$	(5.0	)

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Rate Matters (Tables)

3 Months Ended

Mar. 31, 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

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

The following table reflects the administrative law judges’ (ALJs’) position and PUCT’s decision:

	ALJs’ Proposal			PUCT
(Millions of Dollars)	for Decision			Decision
SPS’ revised rate request	$	42.1		$	42.1
Investment for capital expenditures — post-test year adjustments	(8.9		)	(8.9		)
Lower ROE	(6.3		)	(6.3		)
Lower capital structure	—			(3.7		)
Annual incentive compensation	(0.2		)	(0.3		)
O&M expense adjustments	(4.6		)	(4.6		)
Depreciation expense	(2.7		)	(2.7		)
Property taxes	(0.9		)	(0.9		)
Revenue adjustments	(1.1		)	(1.6		)
Wholesale load reductions	—			(11.5		)
SPP transmission expansion plan	(4.2		)	(4.2		)
Other, net	1.4			(1.2		)
Total, gross of rate case expenses	$	14.6		$	(3.8	)
Adjustment to move rate case expenses to a separate docket	(0.2		)	(0.2		)
Total, net of rate case expenses	$	14.4		$	(4.0	)
New depreciation rates	(11.2		)	(11.2		)
Earnings impact	$	3.2		$	(15.2	)

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Borrowings and Other Financing Instruments (Tables)

3 Months Ended

Mar. 31, 2016

Borrowings and Other Financing Instruments [Abstract]

Credit Facilities

At March 31, 2016, SPS had the following committed credit facility available (in millions of dollars):

Credit Facility (a)		Drawn(b)		Available
$	400	$	87	$	313

^(a)  This credit facility expires in October 2019.

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

Money Pool

Borrowings and Other Financing Instruments [Abstract]

Short-Term Borrowings

Money pool borrowings for SPS were as follows:

(Amounts in Millions, Except Interest Rates)	Three Months Ended March 31, 2016			Twelve Months Ended Dec. 31, 2015
Borrowing limit	$	100		$	100
Amount outstanding at period end	—			—
Average amount outstanding	11			21
Maximum amount outstanding	88			100
Weighted average interest rate, computed on a daily basis	0.71		%	0.40		%
Weighted average interest rate at period end	N/A			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 March 31, 2016			Twelve Months Ended Dec. 31, 2015
Borrowing limit	$	400		$	400
Amount outstanding at period end	80			15
Average amount outstanding	58			100
Maximum amount outstanding	93			246
Weighted average interest rate, computed on a daily basis	0.65		%	0.46		%
Weighted average interest rate at period end	0.70			0.60

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Fair Value of Financial Assets and Liabilities (Tables)

3 Months Ended

Mar. 31, 2016

Fair Value Disclosures [Abstract]

Gross Notional Amounts of Commodity FTRs

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

(Amounts in Thousands) (a)	March 31, 2016	Dec. 31, 2015
Megawatt hours of electricity	2,691	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 March 31, 2016:

	March 31, 2016
	Fair Value						Fair Value Total		Counterparty Netting (b)
(Thousands of Dollars)	Level 1		Level 2		Level 3							Total
Current derivative assets
Other derivative instruments:
Electric commodity	$	—	$	—	$	3,118	$	3,118	$	(1,388	)	$	1,730
Total current derivative assets	$	—	$	—	$	3,118	$	3,118	$	(1,388	)	1,730
PPAs (a)												6,709
Current derivative instruments												$	8,439
Noncurrent derivative assets
PPAs (a)												$	24,482
Noncurrent derivative instruments												$	24,482
Current derivative liabilities
Other derivative instruments:
Electric commodity	$	—	$	—	$	1,388	$	1,388	$	(1,388	)	$	—
Total current derivative liabilities	$	—	$	—	$	1,388	$	1,388	$	(1,388	)	—
PPAs (a)												3,565
Current derivative instruments												$	3,565
Noncurrent derivative liabilities
PPAs (a)												$	26,187
Noncurrent derivative instruments												$	26,187

^(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 March 31, 2016. At March 31, 2016, derivative assets and liabilities include no obligations to return cash collateral or rights to reclaim cash collateral. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.

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

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

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

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

Changes in Level 3 Commodity Derivatives

The following table presents the changes in Level 3 commodity derivatives for the three months ended March 31, 2016 and 2015:

	Three Months Ended March 31
(Thousands of Dollars)	2016			2015
Balance at Jan. 1	$	5,060		$	15,884
Purchases	1,843			4,928
Settlements	(13,219		)	(8,379		)
Net transactions recorded during the period:
Gains (losses) recognized as regulatory assets and liabilities	8,046			(5,976		)
Balance at March 31	$	1,730		$	6,457

Carrying Amount and Fair Value of Long-term Debt

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

	March 31, 2016				Dec. 31, 2015
(Thousands of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current portion (a)	$	1,538,842	$	1,728,470	$	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 (Expense), Net (Tables)

3 Months Ended

Mar. 31, 2016

Other Income and Expenses [Abstract]

Other Income (Expense), Net

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

	Three Months Ended March 31
(Thousands of Dollars)	2016			2015
Interest income	$	85		$	32
Other nonoperating (expense) income	(51		)	45
Insurance policy expense	—			(133		)
Other income (expense), net	$	34		$	(56	)

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Benefit Plans and Other Postretirement Benefits (Tables)

3 Months Ended

Mar. 31, 2016

Compensation and Retirement Disclosure [Abstract]

Components of Net Periodic Benefit Cost (Credit)

Components of Net Periodic Benefit Cost (Credit)

	Three Months Ended March 31
	2016			2015			2016			2015
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Service cost	$	2,440		$	2,752		$	194		$	239
Interest cost	5,315			5,046			455			436
Expected return on plan assets	(6,901		)	(7,153		)	(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	78			713			—			—
Net benefit cost (credit) recognized for financial reporting	$	3,929		$	5,140		$	(191	)	$	(220	)

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Other Comprehensive Income (Tables)

3 Months Ended

Mar. 31, 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 months ended March 31, 2016 and 2015 were as follows:

	Three Months Ended March 31, 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	—			12			12
Losses reclassified from net accumulated other comprehensive loss	42			—			42
Net current period other comprehensive loss	42			12			54
Accumulated other comprehensive loss at March 31	$	(775	)	$	(452	)	$	(1,227	)

	Three Months Ended March 31, 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	42
Net current period other comprehensive loss	42
Accumulated other comprehensive loss at March 31	$	(947	)

Reclassifications out of Accumulated Other Comprehensive Loss

Reclassifications from accumulated other comprehensive loss for the three months ended March 31, 2016 and 2015 were as follows:

	Amounts Reclassified from Accumulated Other Comprehensive Loss
(Thousands of Dollars)	Three Months Ended March 31, 2016				Three Months Ended March 31, 2015
Losses on cash flow hedges:
Interest rate derivatives	$	67		(a)	$	66		(a)
Total, pre-tax	67				66
Tax benefit	(25		)		(24		)
Total amounts reclassified, net of tax	$	42			$	42

^(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	Mar. 31, 2016	Dec. 31, 2015
Accounts receivable, net
Accounts receivable	$ 79,336	$ 77,054
Less allowance for bad debts	(5,876)	(5,888)
Accounts receivable, net	$ 73,460	$ 71,166

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Selected Balance Sheet Data Balance Sheet Related Disclosures, Inventories (Details) - USD ($) $ in Thousands	Mar. 31, 2016	Dec. 31, 2015
Public Utilities, Inventory [Line Items]
Inventories	$ 31,271	$ 37,546
Materials and supplies
Public Utilities, Inventory [Line Items]
Inventories	24,847	24,888
Fuel
Public Utilities, Inventory [Line Items]
Inventories	$ 6,424	$ 12,658

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Selected Balance Sheet Data Balance Sheet Related Disclosures, Property, Plant and Equipment (Details) - USD ($) $ in Thousands	Mar. 31, 2016	Dec. 31, 2015
Public Utility, Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	$ 6,295,305	$ 6,170,461
Less accumulated depreciation	(1,855,138)	(1,821,638)
Property, plant and equipment, net	4,440,167	4,348,823
Electric plant
Public Utility, Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	5,989,862	5,933,764
Construction work in progress
Public Utility, Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	$ 305,443	$ 236,697

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Income Taxes (Details) - USD ($)	3 Months Ended	9 Months Ended
	Mar. 31, 2016	Sep. 30, 2015	Sep. 30, 2012	Dec. 31, 2015
Unrecognized Tax Benefits [Abstract]
Unrecognized tax benefit - Permanent tax positions	$ 2,600,000			$ 2,600,000
Unrecognized tax benefit - Temporary tax positions	21,700,000			22,100,000
Total unrecognized tax benefit	24,300,000			24,700,000
NOL and tax credit carryforwards	(5,000,000)			(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]
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
TEXAS
Tax Audits [Abstract]
Year(s) under examination	2009 and 2010

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Rate Matters (Details)		1 Months Ended						3 Months Ended
	May. 02, 2016 USD ($)	Apr. 30, 2016 USD ($)	Feb. 29, 2016 USD ($)	Dec. 31, 2015 USD ($) MW	Oct. 31, 2015 USD ($)	Jun. 30, 2015 USD ($)	Dec. 31, 2014 USD ($)	Mar. 31, 2016 USD ($)
NMPRC Proceeding - New Mexico 2015 Electric Rate Case
Public Utilities, General Disclosures [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount					$ 45,400,000
Public Utilities, Requested Return on Equity, Percentage					10.25%
Public Utilities, Requested Rate Base, Amount					$ 734,000,000
Public Utilities, Requested Equity Capital Structure, Percentage					53.97%
Public Utilities, Decrease In Base Fuel Revenues					$ 21,100,000
SPP Open Access Transmission Tariff Upgrade Costs
Public Utilities, General Disclosures [Line Items]
Public Utilities, Accrual For Transmission Service Upgrades								$ 0
Southwest Power Pool (SPP) | SPP Open Access Transmission Tariff Upgrade Costs
Public Utilities, General Disclosures [Line Items]
Public Utilities, Maximum Retroactive Charges Indicated by Filing								$ 720,000,000
Subsequent Event | NMPRC Proceeding - New Mexico 2015 Electric Rate Case
Public Utilities, General Disclosures [Line Items]
Public Utilities, Non-fuel Base Rate Increase Under the Stipulation	$ 23,500,000
Public Utilities, Decrease In Base Fuel Revenues Under the Stipulation	$ 21,100,000
SPS | PUCT Proceeding - Texas 2015 Electric Rate Case
Public Utilities, General Disclosures [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount				$ 42,100,000		$ 42,100,000	$ 64,800,000
Public Utilities, Requested Rate Increase (Decrease), Percentage							6.70%
Public Utilities, Requested Return on Equity, Percentage							10.25%
Public Utilities, Requested Rate Base, Amount							$ 1,600,000,000
Public Utilities, Requested Equity Capital Structure, Percentage							53.97%
Public utilities, Additional capital investment							$ 392,000,000
SPS | PUCT Proceeding - Texas 2016 Electric Rate Case
Public Utilities, General Disclosures [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount			$ 71,900,000
Public Utilities, Requested Rate Increase (Decrease), Percentage			14.40%
Public Utilities, Requested Return on Equity, Percentage			10.25%
Public Utilities, Requested Rate Base, Amount			$ 1,700,000,000
Public Utilities, Requested Equity Capital Structure, Percentage			53.97%
SPS | Administrative Law Judge | PUCT Proceeding - Texas 2015 Electric Rate Case
Public Utilities, General Disclosures [Line Items]
Public Utilities, Post Test Year Decrease Adjustments				(8,900,000)
Public Utilities, Decrease To Requested Return On Equity				(6,300,000)
Public Utilities, Decrease to Cost of Debt and Capital Structure				0
Public Utilities, Decrease to annual incentive compensation				(200,000)
Public Utilities, Decrease to O&M Expenses				(4,600,000)
Public Utilities, Decrease to Depreciation Expense				(2,700,000)
Public Utilities, Decrease To Property Taxes				(900,000)
Public Utilities, Decrease to Revenue Adjustments				(1,100,000)
Public Utilities, Decrease To Wholesale Load Reductions				0
Public Utilities, Decrease To Transmission Expansion plan				(4,200,000)
Public Utilities, Increase Related To Other, Net				1,400,000
Public Utilities, Recommended Rate Increase (Decrease) (Including Case Expenses)				14,600,000
Public Utilities, Decrease Adjustment To Move Rate Case Expenses To Separate Docket				(200,000)
Public Utilities, Recommended Rate Increase (Decrease), Amount				14,400,000
Public Utilities, Impact Of New Depreciation Rules				(11,200,000)
Public Utilities, Earnings Impact				$ 3,200,000
SPS | Public Utility Commission of Texas | PUCT Proceeding - Texas 2015 Electric Rate Case
Public Utilities, General Disclosures [Line Items]
Public Utilities, Original Wholesale Load Reduction | MW				500
Public Utilities, Disallowance of Requested Wholesale Load Reduction | MW				300
Public Utilities, Approved Equity Capital Structure, Percentage				51.00%
Public Utilities, Approved Return on Equity, Percentage				9.70%
Public Utilities, Post Test Year Decrease Adjustments				$ (8,900,000)
Public Utilities, Decrease To Requested Return On Equity				(6,300,000)
Public Utilities, Decrease to Cost of Debt and Capital Structure				(3,700,000)
Public Utilities, Decrease to annual incentive compensation				(300,000)
Public Utilities, Decrease to O&M Expenses				(4,600,000)
Public Utilities, Decrease to Depreciation Expense				(2,700,000)
Public Utilities, Decrease To Property Taxes				(900,000)
Public Utilities, Decrease to Revenue Adjustments				(1,600,000)
Public Utilities, Decrease To Wholesale Load Reductions				(11,500,000)
Public Utilities, Decrease To Transmission Expansion plan				(4,200,000)
Public Utilities, Decrease related to other, net				(1,200,000)
Public Utilities, Approved Rate Increase (Decrease) (Including Case Expenses)				(3,800,000)
Public Utilities, Decrease Adjustment To Move Rate Case Expenses To Separate Docket				(200,000)
Public Utilities, Approved Rate Increase (Decrease), Amount				(4,000,000)
Public Utilities, Impact Of New Depreciation Rules				(11,200,000)
Public Utilities, Earnings Impact				$ (15,200,000)
SPS | Subsequent Event | PUCT Proceeding - Texas 2016 Electric Rate Case
Public Utilities, General Disclosures [Line Items]
Public utilities, Additional capital investment		$ 38,900,000
Public Utilities, Increase Related To Other, Net		3,800,000
Public Utilities, Revised requested rate increase		68,600,000
Public Utilities, Increase (Decrease) to Jurisdictional Allocation Factors		9,800,000
Public Utilities, ROE and Capital Structure		11,600,000
Public Utilities, Increase (Decrease) to Rate Case Expenses		$ 4,500,000

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Commitments and Contingencies, Purchased Power Agreements (Details) - Independent Power Producing Entities - MW	3 Months Ended	12 Months Ended
	Mar. 31, 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	1 Months Ended	3 Months Ended
	Feb. 29, 2016	Mar. 31, 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
Number of months in which the state would have to submit an implementation plan for the respective nonattainment areas		18 months
Number of years for the state to achieve the designated attainment standard		5 years
Capital Addition Purchase Commitments | Regional Haze Rules
Environmental Requirements [Abstract]
Liability for estimated cost to comply with regulation		$ 600
Minimum | Implementation of the National Ambient Air Quality Standard for Sulfur Dioxide
Environmental Requirements [Abstract]
Number of units which sulfur dioxide controls could be required		1

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Borrowings and Other Financing Instruments, Short-Term Borrowings (Details) - USD ($)	3 Months Ended	12 Months Ended
	Mar. 31, 2016	Dec. 31, 2015
Short-term Debt [Line Items]
Amount outstanding at period end	$ 80,000,000	$ 15,000,000
Money Pool
Short-term Debt [Line Items]
Borrowing limit	100,000,000	100,000,000
Amount outstanding at period end	0	0
Average amount outstanding	11,000,000	21,000,000
Maximum amount outstanding	$ 88,000,000	$ 100,000,000
Weighted average interest rate, computed on a daily basis (percentage)	0.71%	0.40%
Commercial Paper
Short-term Debt [Line Items]
Borrowing limit	$ 400,000,000	$ 400,000,000
Amount outstanding at period end	80,000,000	15,000,000
Average amount outstanding	58,000,000	100,000,000
Maximum amount outstanding	$ 93,000,000	$ 246,000,000
Weighted average interest rate, computed on a daily basis (percentage)	0.65%	0.46%
Weighted average interest rate at period end (percentage)	0.70%	0.60%

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Borrowings and Other Financing Instruments, Letters of Credit (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2016	Dec. 31, 2015
Line of Credit Facility [Line Items]
Amount outstanding at period end	$ 80,000	$ 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 ($)		3 Months Ended
		Mar. 31, 2016	Dec. 31, 2015
Line of Credit Facility [Line Items]
Debt Instrument, Maturity Date		Oct. 31, 2019
Credit Facility	[1]	$ 400,000,000
Drawn	[2]	87,000,000
Available		313,000,000
Direct advances on the credit facility outstanding		$ 0	$ 0

[1] This credit facility expires in October 2019.

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

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Fair Value of Financial Assets and Liabilities, Derivative Instruments (Details) MWh in Thousands, $ in Millions		Mar. 31, 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		7
Credit Concentration Risk | No Investment Grade Ratings from External Credit Rating Agencies
Consideration of Credit Risk and Concentrations [Abstract]
Number of most significant counterparties for wholesale, trading and non-trading commodity activities with credit exposure | Counterparty		7
Wholesale, trading and non-trading commodity credit exposure for the most significant counterparties | $		$ 43.3
Percentage of wholesale, trading and non-trading commodity credit exposure for the most significant counterparties (in hundredths)		53.00%
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]	2,691	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
	Mar. 31, 2016	Mar. 31, 2015
Financial Impact of Qualifying Fair Value Hedges on Earnings [Abstract]
Derivative instruments designated as fair value hedges	$ 0	$ 0
Recognized gains (losses) from fair value hedges or related hedged transactions	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
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	1,300,000	(800,000)
Pre-tax (gains) losses reclassified into income during the period from regulatory assets and (liabilities)	$ (2,100,000)	$ 100,000

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Fair Value of Financial Assets and Liabilities, Fair Value Measurements (Details) - USD ($)	Mar. 31, 2016		Dec. 31, 2015
Derivatives, Fair Value [Line Items]
Derivative Asset, Collateral, Obligation to Return Cash, Offset	$ 0		$ 0
Derivative Liability, Collateral, Right to Reclaim Cash, Offset	0		0
Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	8,439,000		12,952,000
Other Noncurrent Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	24,482,000		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	26,187,000		27,078,000
Fair Value Measured on a Recurring Basis | Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	1,730,000		5,060,000
Fair Value Measured on a Recurring Basis | Other Current Assets | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	1,730,000		5,060,000
Fair Value Measured on a Recurring Basis | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	0		0
Fair Value Measured on a Recurring Basis | Other Current Liabilities | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	0		0
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0		0
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Assets | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0		0
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	0		0
Fair Value Measured on a Recurring Basis | Level 1 | Other Current Liabilities | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	0		0
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0		0
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Assets | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0		0
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	0		0
Fair Value Measured on a Recurring Basis | Level 2 | Other Current Liabilities | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	0		0
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	3,118,000		8,980,000
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Assets | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	3,118,000		8,980,000
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	1,388,000		3,920,000
Fair Value Measured on a Recurring Basis | Level 3 | Other Current Liabilities | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	1,388,000		3,920,000
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	3,118,000		8,980,000
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Assets | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	3,118,000		8,980,000
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	1,388,000		3,920,000
Fair Value Measured on a Recurring Basis | Fair Value Total | Other Current Liabilities | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	1,388,000		3,920,000
Fair Value Measured on a Recurring Basis | Netting | Other Current Assets
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	(1,388,000)	[1]	(3,920,000)	[2]
Fair Value Measured on a Recurring Basis | Netting | Other Current Assets | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	(1,388,000)	[1]	(3,920,000)	[2]
Fair Value Measured on a Recurring Basis | Netting | Other Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	(1,388,000)	[1]	(3,920,000)	[2]
Fair Value Measured on a Recurring Basis | Netting | Other Current Liabilities | Other Derivative Instruments | Electric Commodity
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	(1,388,000)	[1]	(3,920,000)	[2]
Fair Value, Measurements, Nonrecurring | Other Current Assets | Purchased Power Agreements
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	6,709,000	[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	24,482,000	[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	$ 26,187,000	[3]	$ 27,078,000	[4]

[1] SPS nets derivative instruments and related collateral in its balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at March 31, 2016. At March 31, 2016, derivative assets and liabilities include no obligations to return cash collateral or rights to reclaim cash collateral. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.

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

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

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

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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
	Mar. 31, 2016	Mar. 31, 2015
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Balance at beginning of period	$ 5,060,000	$ 15,884,000
Purchases	1,843,000	4,928,000
Settlements	(13,219,000)	(8,379,000)
Gains (losses) recognized as regulatory assets and liabilities	8,046,000	(5,976,000)
Balance at end of period	1,730,000	6,457,000
Transfers into Level 3	0	0
Transfers out of Level 3	$ 0	$ 0

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Fair Value of Financial Assets and Liabilities, Fair Value of Long-Term Debt (Details) - USD ($) $ in Thousands		Mar. 31, 2016	Dec. 31, 2015
Carrying Amount
Financial Liabilities, Balance Sheet Groupings [Abstract]
Long-term debt, including current portion	[1]	$ 1,538,842	$ 1,538,522
Fair Value
Financial Liabilities, Balance Sheet Groupings [Abstract]
Long-term debt, including current portion	[1]	$ 1,728,470	$ 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 (Expense), Net (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Other Income and Expenses [Abstract]
Interest income	$ 85	$ 32
Other nonoperating (expense) income		45
Other Nonoperating Expense	(51)
Insurance policy expense	0	(133)
Other income (expense), net	$ 34	$ (56)

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Benefit Plans and Other Postretirement Benefits (Details) $ in Thousands	1 Months Ended	3 Months Ended
	Jan. 31, 2016 USD ($) Plan	Mar. 31, 2016 USD ($)	Mar. 31, 2015 USD ($)
Pension Benefits
Components of Net Periodic Benefit Cost (Credit) [Abstract]
Service cost		$ 2,440	$ 2,752
Interest cost		5,315	5,046
Expected return on plan assets		(6,901)	(7,153)
Amortization of prior service cost (credit)		0	10
Amortization of net loss (gain)		2,997	3,772
Net periodic benefit cost (credit)		3,851	4,427
Defined Benefit Plan Regulatory Adjustments		78	713
Net benefit cost (credit) recognized for financial reporting		3,929	5,140
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	239
Interest cost		455	436
Expected return on plan assets		(594)	(635)
Amortization of prior service cost (credit)		(100)	(100)
Amortization of net loss (gain)		(146)	(160)
Net periodic benefit cost (credit)		(191)	(220)
Defined Benefit Plan Regulatory Adjustments		0	0
Net benefit cost (credit) recognized for financial reporting		$ (191)	$ (220)
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
		Mar. 31, 2016	Mar. 31, 2015
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Accumulated other comprehensive loss at beginning of period		$ (1,281)
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax		12
Losses reclassified from net accumulated other comprehensive loss		42
Net current period other comprehensive income		54
Accumulated other comprehensive loss at end of period		(1,227)
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Total, pre-tax		(35,335)	$ (31,585)
Tax benefit		12,812	11,338
Defined Benefit Pension and Postretirement Items
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Accumulated other comprehensive loss at beginning of period		(464)
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax		12
Losses reclassified from net accumulated other comprehensive loss		0
Net current period other comprehensive income		12
Accumulated other comprehensive loss at end of period		(452)
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		(817)	(989)
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax		0
Losses reclassified from net accumulated other comprehensive loss		42	42
Net current period other comprehensive income		42	42
Accumulated other comprehensive loss at end of period		(775)	(947)
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	66
Tax benefit		(25)	(24)
Total, net of tax		42	42
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	$ 66

[1] Included in interest charges.