SOUTHWESTERN PUBLIC SERVICE CO - FORM 10-Q - August 3, 2015

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

x QUARTERLYREPORTPURSUANTTOSECTION 13 OR 15(d) OFTHESECURITIES EXCHANGEACTOF 1934

For the quarterly periodendedJune 30, 2015

or

 ̈ TRANSITION REPORTPURSUANTTOSECTION 13 OR 15(d) OFTHESECURITIES EXCHANGEACTOF 1934

Commission File Number: 001-03789

Southwestern Public Service Company

(Exact name of registrant as specified in its charter)

NewMexico 75-0575400

(State or other jurisdiction of incorporation or organization) (I.R.S. Employer Identification No.)

Tyler at Sixth

Amarillo, Texas 79101

(Address of principalexecutive offices) (Zip Code)

(303) 571-7511

(Registrant’s telephone number, including area code)

Indicate by checkmarkwhether 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 12months (or forsuch 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 checkmarkwhether the registrant has submitted electronically and posted on its corporate Web site, ifany,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 12months (or forsuch shorter period that the registrant was required to submit and post such files). x Yes  ̈ No

Indicate by checkmarkwhether the registrant is a large accelerated filer,an accelerated filer,a non-accelerated filer, ora 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 ifsmaller reporting company)

Indicate by checkmarkwhether the registrant is a shellcompany (as defined in Rule 12b-2 of the Exchange Act).  ̈ Yes x No

Indicate the number ofshares outstanding ofeach of the issuer’s classes ofcommon stock,as of the latest practicable date.

Class Outstanding at Aug. 3, 2015

Common Stock, $1 par value 100 shares

Southwestern Public Service Company meets the conditions set forth in General Instruction H(1)(a)and (b) of Form10-Qand is therefore filing this Form10-Qwith the reduced disclosure format specified in General Instruction H(2) to

such Form10-Q.

Attached files

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TABLEOFCONTENTS

PARTI— FINANCIALINFORMATION

Iteml — Financial Statements (Unaudited) 3

Item2 — Management’s Discussion and Analysis of Financial Condition and Results of Operations 21

Item4 — Controls and Procedures 23

PARTII— OTHERINFORMATION

Item1 — Legal Proceedings 23

Item1A — Risk Factors 23

Item4 — Mine Safety Disclosures 23

Item5 — Other Information 23

Item6 — Exhibits 24

SIGNATURES 25

Certifications Pursuant to Section 302 1

Certifications Pursuant to Section 906 1

Statement Pursuant to Private Litigation 1

This Form10-Qis filed by Southwestern Public Service Company,a NewMexico 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).

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PART1 — FINANCIALINFORMATION

Item1 — FINANCIALSTATEMENTS

SOUTHWESTERNPUBLICSERVICECOMPANY

STATEMENTS OFINCOME(UNAUDITED)

(amounts in thousands)

Three Months Ended June 30 Six Months Ended June 30

2015 2014 2015 2014

Operating revenues $ 422,985 $ 492,536 $ 846,814 $ 940,936

Operating expenses

Electric fueland purchased power 243,026 314,146 488,825 603,350

Operating and maintenance expenses 73,827 68,963 147,724 138,361

Demand side management programexpenses 2,760 2,849 6,429 5,913

Depreciation and amortization 36,750 35,071 72,489 65,583

Taxes (other than income taxes) 13,490 12,507 28,456 26,153

Total operating expenses 369,853 433,536 743,923 839,360

Operating income 53,132 59,000 102,891 101,576

Other income (expense), net 156 (129) 100 (88

Allowance for funds used during construction — equity 1,788 2,895 3,493 6,535

Interestcharges andfinancing costs

Interest charges — includes other financing costs of

$771, $731, $1,544 and $1,461, respectively 21,074 19,645 41,958 38,926

Allowance for funds used during construction — debt (1,137) (1,721) (2,198) (3,848

Total interest charges and financing costs 19,937 17,924 39,760 35,078

Income before income taxes 35,139 43,842 66,724 72,945

Income taxes 12,563 15,807 23,901 26,175

Net income $ 22,576 $ 28,035 $ 42,823 $ 46,770

See Notes to Financial Statements

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SOUTHWESTERNPUBLICSERVICECOMPANY

STATEMENTS OFCOMPREHENSIVEINCOME(UNAUDITED)

(amounts in thousands)

Three Months Ended June 30 Six Months Ended June 30

2015 2014 2015 2014

Net income $ 22,576 $ 28,035 $ 42,823 $ 46,770

Other comprehensive income

Derivative instruments:

Reclassification of losses to net income, net of taxof $24 and $48 foreach of the three and sixmonths ended June 30, 2015 and

2014, respectively 43 42 85 85

Othercomprehensive income 43 42 85 85

Comprehensive income $ 22,619 $ 28,077 $ 42,908 $ 46,855

See Notes to Financial Statements

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SOUTHWESTERNPUBLICSERVICECOMPANY

STATEMENTS OFCASHFLOWS (UNAUDITED)

(amounts in thousands)

Six Months Ended June 30

2015 2014

Operating activities

Net income $ 42,823 $ 46,770

Adjustments to reconcile net income to cash provided by operating activities:

Depreciation and amortization 73,628 66,692

Demand side management programamortization 837 837

Deferred income taxes 11,866 51,678

Amortization of investment taxcredits (170) (170

Allowance forequity funds used during construction (3,493) (6,535

Net derivative losses 133 133

Changes in operating assets and liabilities:

Accounts receivable (19,478) (15,131

Accrued unbilled revenues 10,927 (33,034

Inventories 10,776 2,022

Prepayments and other (21,378) (12,786

Accounts payable (10,210) 16,949

Net regulatory assets and liabilities 41,291 (34,055

Othercurrent liabilities 13,510 1,536

Pension and otheremployee benefit obligations (10,435) (3,122

Change in other noncurrent assets 607 3,558

Change in other noncurrent liabilities 606 2,198

Net cash provided by operating activities 141,840 87,540

Investing activities

Utility capital/construction expenditures (280,615) (281,398

Allowance forequity funds used during construction 3,493 6,535

Investments in utility money poolarrangement (9,000) (22,000

Repayments fromutility money poolarrangement 9,000 22,000

Net cash used in investing activities (277,122) (274,863

Financing activities

Proceeds from(repayment of)short-termborrowings, net 172,000 15,000

(Repayment of) proceeds fromissuance of long-termdebt (85) 148,510

Borrowings under utility money poolarrangement 163,700 382,000

Repayments under utility money poolarrangement (179,700) (420,000

Capitalcontributions fromparent 34,535 100,000

Dividends paid to parent (53,167) (36,264

Net cash provided by financing activities 137,283 189,246

Net change in cash and cash equivalents 2,001 1,923

Cash and cash equivalents at beginning of period 596 1,011

Cash and cash equivalents at end of period $ 2,597 $ 2,934

Supplemental disclosure ofcash flowinformation:

Cash paid for interest (net ofamounts capitalized) $ (38,527) $ (33,668

Cash (paid) received for income taxes, net (36,992) 8,705

Supplemental disclosure of non-cash investing transactions:

Property, plant and equipment additions in accounts payable $ 26,513 $ 22,423

See Notes to Financial Statements

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SOUTHWESTERNPUBLICSERVICECOMPANY

BALANCESHEETS (UNAUDITED)

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

June 30, 2015 Dec. 31, 2014

Assets

Current assets

Cash and cash equivalents $ 2,597 $ 596

Accountsreceivable, net 78,386 71,626

Accountsreceivablefromaffiliates 14,701 1,983

Accrued unbilled revenues 118,360 129,287

Inventories 32,455 43,231

Regulatory assets 36,554 52,006

Derivativeinstruments 19,355 23,776

Deferred incometaxes 91,672 51,854

Prepaymentsand other 52,854 31,476

Totalcurrent assets 446,934 405,835

Property, plant and equipment, net 3,948,839 3,743,141

Other assets

Regulatory assets 308,519 323,305

Derivativeinstruments 29,218 33,164

Other 14,918 15,859

Total other assets 352,655 372,328

Totalassets $ 4,748,428 $ 4,521,304

Liabilities and Equity

Current liabilities

Short-termdebt $ 209,000 $ 37,000

Borrowings under utility money poolarrangement — 16,000

Accounts payable 148,722 160,762

Accounts payableto affiliates 14,970 19,790

Regulatory liabilities 115,316 87,723

Taxesaccrued 24,017 27,208

Accrued interest 17,071 17,057

Dividends payable 23,025 27,828

Derivativeinstruments 3,565 3,565

Other 90,838 80,211

Totalcurrent liabilities 646,524 477,144

Deferred creditsand other liabilities

Deferred incometaxes 899,063 849,145

Regulatory liabilities 105,051 115,188

Asset retirement obligations 26,713 26,031

Derivativeinstruments 28,860 30,643

Pension and employee benefit obligations 93,166 103,670

Other 9,643 9,320

Total deferred creditsand other liabilities 1,162,496 1,133,997

Commitmentsand contingencies

Capitalization

Long-termdebt 1,349,858 1,349,691

Common stock —200 sharesauthorized of $1.00 par value; 100 shares outstanding at

June 30, 2015 andDec. 31, 2014, respectively — —

Additional paid in capital 1,199,998 1,165,463

Retained earnings 390,456 395,998

Accumulated other comprehensiveloss (904) (989

Totalcommon stockholder’sequity 1,589,550 1,560,472

Total liabilitiesand equity $ 4,748,428 $ 4,521,304

See Notes to Financial Statements

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SOUTHWESTERNPUBLICSERVICECOMPANY

Notes to Financial Statements (UNAUDITED)

In the opinion ofmanagement, the accompanying unaudited financialstatements contain alladjustments necessary to present fairly, in accordance with accounting principles generally accepted in the United States of America (GAAP),

the financial position of SPS as ofJune 30, 2015,and Dec. 31, 2014; the results of its operations, including the components of net income and comprehensive income, for the three and sixmonths ended June 30, 2015 and 2014; and its

cash flows for the sixmonths ended June 30, 2015 and 2014. Alladjustments are ofa normal, recurring nature,except as otherwise disclosed. Management has also evaluated the impact ofevents occurring afterJune 30, 2015 up to the

date of issuance of these financialstatements. These statements contain all necessary adjustments and disclosures resulting fromthat evaluation. The Dec. 31, 2014 balance sheet information has been derived fromthe audited 2014

financialstatements included in the SPS Annual Report on Form10-Kfor the yearended Dec. 31, 2014. These notes to the financialstatements have been prepared pursuant to the rules and regulations of the SECfor Quarterly Reports

on Form10-Q. Certain information and note disclosures normally included in financialstatements 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 financialstatements and notes thereto included in the SPS Annual Report on Form10-Kfor the yearended Dec. 31, 2014, filed with the SECon Feb. 23, 2015. Due to the seasonality of SPS’electric sales,

interimresults are not necessarily an appropriate base fromwhich to project annual results.

1. Summary of Significant Accounting Policies

The significant accounting policies set forth in Note 1 to the financialstatements in the SPS Annual Report on Form10-Kfor the yearended Dec. 31, 2014,appropriately represent, in allmaterial respects, the current status ofaccounting

policies and are incorporated herein by reference.

2. Accounting Pronouncements

RecentlyIssued

Revenue Recognition—In May 2014, the FinancialAccounting Standards Board (FASB) issued Revenue fromContracts 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 newguidance also includes additional disclosure requirements

regarding revenue,cash flows and obligations related to contracts with customers. As a result of the FASB’s deferral of the standard’s required implementation date in July 2015, the guidance is effective for interimand annual reporting

periods beginning after Dec. 15, 2017. SPS is currently evaluating the impact ofadopting ASU2014-09 on its financialstatements.

Consolidation—In February 2015, the FASBissued Amendments to the Consolidation Analysis, Topic 810 (ASUNo. 2015-02), which reduces the number ofconsolidation models and amends certain consolidation principles related

to variable interest entities. This guidance will be effective for interimand annual reporting periods beginning after Dec. 15. 2015,and early adoption is permitted. SPS is currently evaluating the impact ofadopting ASU2015-02 on its

financialstatements.

Presentation ofDebt Issuance Costs —In April 2015, the FASBissued Simplifying the Presentation ofDebt Issuance Costs, Subtopic 835-30 (ASUNo. 2015-03), which amends existing guidance to require the presentation of debt

issuance costs on the balance sheet as a deduction fromthe carrying amount of the related debt, instead ofan asset. This guidance will be effective for interimand annual reporting periods beginning after Dec. 15, 2015,and early

adoption is permitted. Other than the prescribed reclassification ofassets to an offset of debt on the balance sheets, SPS does not expect the implementation of ASU2015-03 to have a material impact on its financialstatements.

Fair Value Measurement —In May 2015, the FASBissued Disclosures for Investments in Certain Entities that Calculate Net Asset Value per Share (or Its Equivalent), Topic 820 (Accounting Standards Update (ASU) No. 2015-

07), which removes the requirement to categorize within the fair value hierarchy the fair values for investments measured using a net asset value methodology. This guidance will be effective on a retrospective basis for interimand

annual reporting periods beginning after Dec. 15, 2015,and early adoption is permitted. Other than the reduced disclosure requirements, SPS does not expect the implementation of ASU2015-07 to have a material impact on its financial

statements.

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3. SelectedBalance Sheet Data

(Thousands of Dollars) June 30, 2015 Dec. 31, 2014

Accounts receivable, net

Accounts receivable $ 84,326 $ 77,465

Less allowance for bad debts (5,940) (5,839

$ 78,386 $ 71,626

(Thousands of Dollars) June 30, 2015 Dec. 31, 2014

Inventories Materials and supplies $ 25,018 $ 24,738

Fuel 7,437 18,493

$ 32,455 $ 43,231

(Thousands of Dollars) June 30, 2015 Dec. 31, 2014

Property, plant andequipment, net

Electric plant $ 5,580,225 $ 5,376,606

Construction work in progress 291,565 238,519

Total property, plant and equipment 5,871,790 5,615,125

Less accumulated depreciation (1,922,951) (1,871,984

$ 3,948,839 $ 3,743,141

4. Income Taxes

Except to the extent noted below, Note 6 to the financialstatements included in SPS’ Annual Report on Form10-Kfor the yearended Dec. 31, 2014 appropriately represents, in allmaterial 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 taxreturn. The statute of limitations applicable to Xcel Energy’s 2009 federal income taxreturn expires in March 2016. In the

third quarter of 2012, the Internal Revenue Service (IRS)commenced an examination of taxyears 2010 and 2011, including a 2009 carryback claim. As ofJune 30, 2015, the IRS had proposed an adjustment to the federal taxloss carryback

claims that would result in $12million of income taxexpense for the 2009 through 2011 claims, the recently filed 2013 claim,and the anticipated claimfor 2014. SPS is not expected to accrue any income taxexpense related to this

adjustment. As ofJune 30, 2015, the IRS has begun the appeals process; however, the outcome and timing ofa resolution are uncertain.

State Audits — SPS is a member of the Xcel Energy affiliated group that files consolidated state income taxreturns. As ofJune 30, 2015, SPS’earliest open taxyear that is subject to examination by state taxing authorities under

applicable statutes of limitations is 2009. There are currently no state income taxaudits in progress.

Unrecognized Tax Benefits — The unrecognized taxbenefit balance includes permanent taxpositions, which if recognized would affect the annualeffective taxrate (ETR). In addition, the unrecognized taxbenefit balance includes

temporary taxpositions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing ofsuch deductibility. A change in the period of deductibility would not affect the ETRbut would accelerate

the payment ofcash to the taxing authority to an earlier period.

A reconciliation of the amount of unrecognized taxbenefit is as follows:

(Millions of Dollars) June 30, 2015 Dec. 31, 2014

Unrecognized taxbenefit — Permanent taxpositions $ 1.6 $ 1.5

Unrecognized taxbenefit — Temporary taxpositions 12.6 11.7

Total unrecognized taxbenefit $ 14.2 $ 13.2

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The unrecognized taxbenefit amounts were reduced by the taxbenefits associated with net operating loss (NOL)and taxcredit carryforwards. The amounts of taxbenefits associated with NOLand taxcredit carryforwards are as

follows:

(Millions of Dollars) June 30, 2015 Dec. 31, 2014

NOLand taxcredit carryforwards $ (6.0) $ (4.8

It is reasonably possible that SPS’amount of unrecognized taxbenefits could significantly change in the next 12months as the IRS appeals process progresses and state audits resume. As the IRS examination moves closer to

completion, it is reasonably possible that the amount of unrecognized taxbenefit could decrease up to approximately $2million.

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

5. Rate Matters

Except to the extent noted below, the circumstances set forth in Note 10 to the financialstatements included in SPS’ Annual Report on Form10-Kfor the yearended Dec. 31, 2014 appropriately represent, in allmaterial 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 retailelectric rate case in Texas seeking an overall increase in annual revenue ofapproximately $64.8million, or 6.7 percent. The filing was based on a historic test year

ending June 2014,adjusted for known and measurable changes,a return on equity (ROE) of 10.25 percent,an electric rate base ofapproximately $1.6 billion and an equity ratio of 53.97 percent. In March 2015, SPS revised its requested

increase to $58.9million based on updated information.

SPS is seeking a waiver of the PUCT post-test yearadjustment rule which would allowfor inclusion of $392million (SPS totalcompany)additionalcapital investment for the period July 1, 2014 through Dec. 31, 2014.

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

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

• The OPUCrecommended a rate increase of $1.8million,an ROEof 9.20 percent and an equity ratio of 52.38 percent.

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

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

SPS Rebuttal

(Millions of Dollars) AXM OPUC Staff Testimony

SPS’revisedrate request $ 58.9 $ 58.9 $ 58.9 $ 58.9

Investment forcapitalexpenditures — post-test yearadjustments (11.3) (23.8) (23.8) —

Lower ROE (10.9) (13.5) (12.1) —

Rate base adjustments (largely the removal of the prepaid pension asset) (6.2) (6.8) — —

O&M expense adjustments (13.7) (11.0) (7.9) (1.6

Depreciation expense (13.3) — — —

Property taxes — (1.2) (4.4) (1.8

Revenue adjustments (2.2) (0.2) — —

Wholesale load reductions (13.2) — (11.1) —

Southwest Power Pool (SPP) transmission expansion plan — — — (7.3

Other, net (1.7) (0.6) (2.2) (1.8

Total recommendation $ (13.6) $ 1.8 $ (2.6) $ 46.4

Adjustment to move rate case expenses to a separate docket — — — (4.3

Recommendation,excluding rate case expenses $ (13.6) $ 1.8 $ (2.6) $ 42.1

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

Pending Regulatory Proceedings —NewMexico Public RegulationCommission (NMPRC)

NewMexico 2015 Electric Rate Case — In June 2015, SPS filed an electric rate case with the NMPRCforan increase in non-fuel base rates of $31.5million and a base fuel decrease of $30.1million. The rate filing was based on a 2016

forecast test year (FTY),a requested return on equity of 10.25 percent,a jurisdictionalelectric rate base of $777.9million and an equity ratio of 53.97 percent.

In June 2015, SPS’ rate case application was dismissed by the NMPRC. The NMPRCdetermined that the filing did not comply with its newinterpretation of the statute regarding FTYperiods and the corresponding timing ofa rate case

submission in relation to the FTYused in the case. This newinterpretation occurred during the recent Public Service Company of NewMexico rate case.

In July, SPS filed an appealwith the NewMexico Supreme Court. In addition, SPS plans to file a rate case later this year.

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

Wholesale Rate ROE Complaints — In April 2012, Golden Spread Electric Cooperative, Inc. (Golden Spread),a wholesale cooperative customer, filed a rate complaint alleging that the base ROEincluded in the SPS production formula

rate for Golden Spread of 10.25 percent,and the SPS transmission base formula rate ROEof 10.77 percent,are unjust and unreasonable,and asking that the ROEs be reduced to 9.15 percent and 9.65 percent, respectively,effective April

20, 2012. In July 2013, Golden Spread filed a second complaint,again asking that the ROEin the SPS production formula rate for Golden Spread and transmission formula rates be reduced to 9.15 and 9.65 percent, respectively,effective

July 19, 2013. In June 2014, the FERCissued orders consolidating the Golden Spread ROEcomplaints and setting the complaints forsettlement judge or hearing procedures.

A third rate complaint was filed in October 2014 by Golden Spread,certain NewMexico cooperatives and the West Texas Municipal Power Agency, requesting that the ROEin certain SPS production formula rates for Golden Spread and

the NewMexico cooperatives and transmission formula rates be reduced, this time to 8.61 percent and 9.11 percent, respectively,effective Oct. 20, 2014. In January 2015, the FERCissued an ordersetting the third complaint for hearing

procedures and granting the complainants’ requested refund effective date. The FERCestablished effective dates for refunds of April 20, 2012 (first refund period), July 19, 2013 (second refund period)and Oct. 20, 2014 (third refund

period), respectively.

SPS sought rehearing of the FERCdecisions to allowback-to-back complaints involving the same issue with consecutive 15month refund periods,asserting this ruling is contrary to the governing statute. On May 12, 2015, FERC

denied the rehearing request as it pertained to the first two rate complaints. In July 2015, SPS filed an appeal to the D.C. Circuit Court of Appeals of the FERCorders in the first two rate complaints allowing the sequentialcomplaints and

consecutive 15month refund periods. The D.C. Circuit Court has not established a proceduralschedule. FERCaction on the similar SPS rehearing request related to the third complaint is pending.

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

Refund

Period Production ROE Transmission ROE

Golden Spread 1 8.78% 9.28%

2 8.51 9.01

3 8.45 8.95

SPS 1 10.25 10.39

2 10.25 11.20

3 10.40 11.20

FERCStaff 1 8.97 9.47

2 8.64 9.14

3 8.53 9.03

Includesa SPP RTOmembership adder up to 50 basis points.

For thethird refund period, therecommended production and transmission ROEsaresupported by Golden Spread, certain NewMexico cooperativesand the West TexasMunicipal Power Agency (transmission ROE only).

In addition to therecommendedROEs, SPSalso filed testimony recommending the ROEsremain unchanged.

10

(a)

(b)

(c)

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Hearings scheduled forJuly 2015 for the first two rate complaints were canceled and the parties agreed to file briefs based on pre-filed testimony. An initialALJ decision on the first two complaints is expected to be issued by Nov. 25,

2015,and a final FERCorder to be issued no earlier than 2016. A hearing for the third rate complaint is scheduled for Oct. 2015, with an ALJ initial decision expected in January 2016 and a final FERCorder no earlier than later in 2016.

SPS recorded a current liability representing the current best estimate ofa refund obligation associated with potential ROEadjustments as ofJune 30, 2015,and is reducing transmission and production revenues, net ofexpense,

between $4million and $6million annually.

2004 FERC Complaint Case Orders — In August 2013, the FERCissued an order related to a 2004 complaint case brought by Golden Spread and Public Service Company of NewMexico (PNM)and an Order on InitialDecision in a

subsequent 2006 production rate case filed by SPS.

The originalcomplaint included two key components: 1) PNM’s claimregarding inappropriate allocation of fuelcosts and 2)a base rate complaint, including the appropriate demand-related cost allocator. The FERCpreviously

determined that the allocation of fuelcosts and the demand-related cost allocator utilized by SPS was appropriate.

In the August 2013Orders, the FERCclarified its previous ruling on the allocation of fuelcosts and reaffirmed that the refunds in question should only apply to firmrequirements customers and not PNM’s contractual load. The FERC

also reversed its prior demand-related cost allocator decision. The FERCstated that it had erred in its initialanalysis and concluded that the SPS systemwas a 3 coincident peak (CP) rather than a 12 CP system.

In September 2013, SPS filed a request for rehearing of the FERCruling on the CP allocation and refund decisions. SPS asserted that the FERCapplied an improper burden of proofand that precedent did not support retroactive refunds.

PNM also requested rehearing of the FERCdecision not to reverse its prior ruling. In October 2013, the FERCissued orders furtherconsidering the requests for rehearing, which are currently pending. As of Dec. 31, 2014, SPS had

accrued $50.4million related to the August 2013Orders and an additional $1.5million of principaland interest has been accrued during 2015.

2015 ProductionFormula Rate Change Filing — In January 2015, SPS filed to revise the production formula rates forsixof its wholesale customers, including Golden Spread,certain NewMexico cooperatives and West Texas Municipal Power Agency,effective Feb. 1, 2015. The filing proposes severalmodifications, including a reduction in wholesale depreciation rates and the use ofa 12 CP demand-related cost allocator forallwholesale customers. In March 2015, the FERCaccepted this filing,effective July 1, 2015, subject to refund and settlement judge or hearing procedures. The parties remain engaged in settlement judge procedures. Effective June 1, 2015, the Golden Spread

contract demand quantity subject to the formula rate change declined from500MW to 300MW.

6. Commitments andContingencies

Except to the extent noted belowand in Note 5 above, the circumstances set forth in Note 5, Notes 10 and 11 to the financialstatements in SPS’ Annual Report on Form10-Kfor the yearended Dec. 31, 2014 and in Notes 5 and 6 to SPS’ Quarterly Report on Form10-Qfor the quarterly period ended March 31, 2015,appropriately represent, in allmaterial respects, the current status ofcommitments 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)

Undercertain PPAs, SPS purchases power fromindependent power producing entities that own natural gas fueled power plants for which SPS is required to reimburse natural gas fuelcosts, 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 827megawatts (MW) ofcapacity under long-termPPAs as ofJune 30, 2015 and Dec. 31, 2014, with entities that have been determined to be variable interest entities. SPS has concluded that these entities are not

required to be consolidated in its financialstatements because it does not have the power to direct the activities that most significantly impact the entities’economic performance. These agreements have expiration dates through 2033

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Environmental Contingencies

Environmental Requirements

Water Federal CleanWater Act (CWA)Waters ofthe United States Rule — In June 2015, the EPA and the U.S. Army Corps of Engineers published a final rule that significantly expands the types of water bodies regulated under the CWA

and broadens the scope of waters subject to federal jurisdiction. The expansion of the term“Waters of the U.S.” willsubject more utility projects to federal CWA jurisdiction, thereby potentially delaying the siting of newgeneration

projects, pipelines, transmission lines and distribution lines,as wellas increasing project costs and expanding permitting and reporting requirements. The rule will go into effect beginning in August 2015. SPS does not anticipate the

costs ofcompliance with the final rule will have a material impact on the results of operations, financial position orcash flows.

Air Cross-State Air PollutionRule(CSAPR)— CSAPRaddresses long range transport of particulate matter (PM)and ozone by requiring reductions in sulfur dioxide (SO )and nitrous oxide (NOx) fromutilities in the eastern half of the United States, including Texas, using an emissions trading program.

In August 2012, the United States District Court of Appeals for the District of Columbia Circuit (D.C. Circuit) vacated the CSAPRand remanded it back to the EPA. The D.C. Circuit stated the EPA must continue administering the Clean Air Interstate Rule (CAIR) pending adoption ofa valid replacement. In April 2014, the U.S. Supreme Court reversed and remanded the case to the D.C. Circuit. The Supreme Court held that the EPA’s rule design did not violate the Clean Air Act (CAA)and that states had received adequate opportunity to develop their own plans. Because the D.C. Circuit overturned the CSAPRon two over-arching issues, there are many other issues the D.C. Circuit did not rule on that were considered on remand. In July 2015, the D.C. Circuit issued an opinion which found the reduction budgets exceed what is necessary for Texas to reduce its impact on downwind states that do not meet ambient air quality

standards. The D.C. Circuit remanded the matter to the EPA to reconsider the emission budgets. While the EPA reconsiders emission budgets, the D.C. Circuit left CSAPRin effect.

In October 2014, the D.C. Circuit granted the EPA’s request to begin to implement CSAPRby imposing its 2012 compliance obligations starting in January 2015. While the litigation continues, the EPA is administering the CSAPRin

2015.

Multiple changes to the SPS systemsince 2011willsubstantially reduce estimated costs ofcomplying with the CSAPR. These include the addition of 700MW of wind power, the construction ofJones Units 3 and 4, reduced wholesale

load, newPPAs, installation of NOxcombustion controls on TolkUnits 1 and 2 and completion ofcertain transmission projects. As a result, SPS estimates compliance with the CSAPRin 2015willcost approximately $7million or less.

Electric Generating Unit (EGU)Mercury and Air Toxics Standards(MATS)Rule —The final EGUMATS rule became effective in April 2012. The EGUMATS rule sets emission limits foracid gases, mercury and other hazardous air

pollutants and requires coal-fired utility facilities greater than 25MW to demonstrate compliance within three to four years of the effective date. In 2014, the U.S. Supreme Court decided to reviewthe D.C. Circuit’s decision that upheld

the MATS standard. By April 2015, the MATS compliance deadline, SPS had met the EGUMATS rule through a combination ofemission control projects and existing controls. Mercury controls were installed in SPS’ Tolk and Harrington plants fora capitalcost of $8million. On June 29, 2015, the U.S. Supreme Court found that the EPA acted unreasonably by not considering the cost to regulate mercury and other hazardous air pollutants. The D.C. Circuit, on

remand, will decide whether to leave MATS in effect while the EPA considers such costs in making a newdetermination. SPS believes EGUMATS costs will be recoverable through regulatory mechanisms and does not anticipate a material impact on the results of operations, financial position orcash flows.

Regional Haze Rules — The regional haze programis designed to address widespread haze that results fromemissions froma multitude ofsources. In 2005, the EPA amended the best available retrofit technology (BART) requirements

of its regional haze rules, which require the installation and operation ofemission controls for industrial facilities emitting air pollutants that reduce visibility in certain national parks and wilderness areas. In its first regional haze state

implementation plan (SIP), Texas identified the SPS facilities that will have to reduce SO , NOxand PM emissions under BART and set emissions limits for those facilities.

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Harrington Units 1 and 2 are potentially subject to BART. Texas developed a SIP that finds the CAIRequal to BART forelectric generating units (EGUs). As a result, no additionalcontrols beyond CAIRcompliance would be required.

In May 2012, the EPA deferred its reviewof the SIP in its final rule allowing states to find that CSAPRcompliance meets BART requirements for EGUs. In December 2014, the EPA proposed to approve the BART portion of the SIP, with

the exception that the EPA would substitute CSAPRcompliance for Texas’ reliance on CAIR. The EPA currently plans to issue its final rule in December 2015.

In May 2014, the EPA issued a request for information under the CAA related to SO controlequipment at TolkUnits 1 and 2. In December 2014, the EPA proposed to disapprove the reasonable progress portions of the SIP and instead

adopt a Federal Implementation Plan. The EPA proposed to require dry scrubbers on both Tolk units to reduce SO emissions to help achieve reasonable progress goals for Texas and Oklahoma national parks and wilderness areas. As

proposed, the dry scrubbers would need to be installed and operating within five years of the EPA’s finalaction,currently expected in December 2015. Whether dry scrubbers are required is dependent on the EPA’s final decision. If

required, they would cost approximately $600million, with an annual operating cost ofapproximately $10.4million. SPS believes these costs would be recoverable through regulatory mechanisms and therefore does not expect a material

impact on results of operations, financial position orcash flows.

Implementation ofthe National Ambient AirQuality Standard (NAAQS)for SO — The EPA adopted a more stringent NAAQS for SO in 2010. In 2013, the EPA designated areas as not attaining the revised NAAQS, which did not

include any areas where Xcel Energy operates power plants. However, many otherareas of the country were unable to be classified by the EPA due to a lack ofairmonitors.

Following a lawsuit alleging that the EPA had not completed its area designations in the time required by the CAA and undera 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 lowsulfurcoal to reduce SO emissions. The Texas Commission on EnvironmentalQuality (TCEQ) is expected to make recommendations for nonattainment

areas to the EPA in September 2015with a decision by summer 2016.

Ifan area is designated nonattainment, the respective states will need to evaluate all SO sources in the area. The state would then submit an implementation plan for the respective areas which would be due in 18months, designed to

achieve the NAAQS within five years. The TCEQcould require additional SO controls on one ormore of the units at Tolk and Harrington. SPS cannot evaluate the impacts of this ruling until the designation of nonattainment areas is made and any required state plans are developed. SPS believes that, should SO controlsystems be required fora plant,compliance costs will be recoverable through regulatory mechanisms and therefore does not expect a material

impact on results of operations, financial position orcash 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 whethera loss is probable or is a reasonable possibility,and whether the loss ora range of loss is

estimable, often involves a series ofcomplexjudgments about future events. Management maintains accruals forsuch losses that are probable of being incurred and subject to reasonable estimation. Management is sometimes unable

to estimate an amount or range ofa 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 ofsuch matters, including a possible eventual loss. Forcurrent proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, ifany,arising fromsuch current proceedings would have a materialeffect on SPS’ financialstatements. Unless otherwise required by GAAP, legal fees are expensed as

incurred.

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7. Borrowings andOther Financing Instruments

Short-TermBorrowings

Money Pool — Xcel Energy Inc.and its utility subsidiaries have established a money poolarrangement that allows forshort-terminvestments 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 poolarrangement does not allowthe utility subsidiaries to make investments in Xcel Energy Inc. Money pool borrowings for SPS were as follows:

(Amounts in Millions, Except Interest Rates) Three Months Ended June 30, 2015 Twelve Months Ended Dec. 31, 2014

Borrowing limit $ 100 $ 100

Amount outstanding at period end — 16

Average amount outstanding 4 9 Maximumamount outstanding 36 100 Weighted average interest rate,computed on a daily basis 0.52% 0.22 Weighted average interest rate at period end N/A 0.45

Commercial Paper —SPSmeets its short-termliquidity requirements primarily through the issuance ofcommercial paperand borrowings under its credit facility. Commercial paper outstanding for SPS was as follows:

(Amounts in Millions, Except Interest Rates) Three Months Ended June 30, 2015 Twelve Months Ended Dec. 31, 2014

Borrowing limit $ 400 $ 400

Amount outstanding at period end 209 37

Average amount outstanding 160 83 Maximumamount outstanding 209 241 Weighted average interest rate,computed on a daily basis 0.48% 0.26 Weighted average interest rate at period end 0.49 0.47

Letters ofCredit — SPS uses letters ofcredit, generally with terms of one year, to provide financial guarantees forcertain operating obligations. At June 30, 2015 and Dec. 31, 2014, there were $36.0million and $30.0million of letters of

credit outstanding, respectively under the credit facility. The contract amounts of these letters ofcredit approximate their fair value and are subject to fees.

Credit Facility —In order to use its commercial paper programto fulfillshort-termfunding needs, SPSmust 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 ofcredit provides short-termfinancing in the formof notes payable to banks, letters ofcredit and back-up support forcommercial

paper borrowings.

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

Credit Facility Drawn Available

$ 400 $ 245 $ 155

Thiscredit facility expiresin October 2019.

Includes outstanding commercial paper and letters of credit.

Allcredit facility bank borrowings, outstanding letters ofcredit and outstanding commercial paper reduce the available capacity under the credit facility. SPS had no direct advances on the credit facility outstanding at June 30, 2015 and Dec. 31, 2014.

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8. Fair Value of Financial Assets andLiabilities

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 identicalassets or liabilities as of the reporting date. The types ofassets 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 ofassets and liabilities included in Level 2 are typically either

comparable to actively traded securities orcontracts, 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 ofassets 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 ofcash equivalents are generally based on cost plus accrued interest; money market funds are measured using quoted net asset values.

Interest rate derivatives —The fair values of interest rate derivatives are based on broker quotes that utilize current market interest rate forecasts.

Commodity derivatives —The methods used to measure the fair value ofcommodity derivative forwards and options utilize forward prices and volatilities,as wellas pricing adjustments forspecific delivery locations,and are generally

assigned a Level 2. When contractualsettlements 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-termforward 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 fromthe SPP, generally referred to as financial transmission rights (FTRs). FTRs purchased froma RTOare financial instruments that

entitle or obligate the holder to monthly revenues orcharges based on transmission congestion across a given transmission path. The value ofan FTRis derived from,and designed to offset, the cost ofenergy 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 ofelectricity pertinent to

a given transmission path. Unplanned plant outages, scheduled plant maintenance,changes in the relative costs of fuels used in generation, weatherand overallchanges in demand forelectricity can each impact the operating

schedules of the power plants on the transmission grid and the value ofan FTR. The valuation process for FTRs utilizes complexiterative modeling to predict the impacts of forecasted changes in these drivers of transmission system

congestion on the historical pricing of FTRpurchases.If forecasted costs ofelectric transmission congestion increase or decrease fora given FTRpath, the value of that particular FTRinstrument will likewise increase or decrease. Given the limited observability ofmanagement’s forecasts forseveral of the inputs to this complexvaluation model - including expected plant operating schedules and retailand wholesale demand, fair value measurements for FTRs

have been assigned a Level 3. Non-trading monthly FTRsettlements are expected to be recovered through fueland 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 financialstatements of SPS.

DerivativeInstruments Fair Value Measurements

SPS enters into derivative instruments, including forward contracts, for trading purposes and to manage risk in connection with changes in interest rates and electric utility commodity prices.

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Interest Rate Derivatives —SPSmay enter into various instruments that effectively fixthe interest payments on certain floating rate debt obligations oreffectively fixthe yield or price on a specified benchmark interest rate foran

anticipated debt issuance fora specific period. These derivative instruments are generally designated as cash flowhedges foraccounting purposes.

At June 30, 2015,accumulated othercomprehensive losses related to interest rate derivatives included $0.2million of net losses expected to be reclassified into earnings during the next 12months 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 ofelectric capacity,energy and energy-related instruments. SPS’ riskmanagement policy

allows management to conduct these activities within guidelines and limitations as approved by its riskmanagement committee, which is made up ofmanagement 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 fromchanges in commodity prices in its electric utility operations,as wellas for trading purposes. This could include the

purchase orsale ofenergy orenergy-related products and FTRs.

The following table details the gross notionalamounts ofcommodity FTRs at June 30, 2015 and Dec. 31, 2014:

(Amounts in Thousands) June 30, 2015 Dec. 31, 2014 Megawatt hours ofelectricity 13,620 6,930

Amountsare not reflective of net positionsin the underlying commodities.

Impact ofDerivative Activities on Income and Accumulated Other Comprehensive Loss —Pre-taxlosses related to interest rate derivatives reclassified fromaccumulated othercomprehensive loss into earnings were $0.1million for

each of the three and sixmonths ended June 30, 2015 and 2014.

During the three and sixmonths ended June 30, 2015,changes in the fair value of FTRs resulted in pre-taxnet losses of $1.2million and $2.0million, respectively, recognized as regulatory assets and liabilities. For the three and six months ended June 30, 2014,changes in the fair value of FTRs resulted in pre-taxnet losses of $1.0million and $2.4million, respectively, recognized as regulatory assets and liabilities. The classification as a regulatory asset or liability is

based on expected recovery of FTRsettlements through fueland purchased energy cost recovery mechanisms.

FTRsettlement gains of $1.7million and $1.6million, respectively, were recognized for the three and sixmonths ended June 30, 2015, respectively, recorded to electric fueland purchased power. For the three and sixmonths ended June

30, 2014, FTRsettlement losses of $1.9million and gains of $0.9million, respectively, were recognized and recorded to electric fueland purchased power. These derivative settlement gains and losses are shared with electric customers

through fueland purchased energy cost-recovery mechanisms,and reclassified out of income as regulatory assets or liabilities,as appropriate.

SPS had no derivative instruments designated as fair value hedges during the three and sixmonths ended June 30, 2015 and 2014. Therefore, no gains or losses fromfair value hedges or related hedged transactions were recognized for

these periods.

Consideration ofCredit 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 performon the transactions set forth in the contracts. Given this assessment,as wellas an assessment of the impact of SPS’ own credit riskwhen determining the fair value of derivative liabilities, the impact of

considering credit riskwas immaterial to the fair value of unsettled commodity derivatives presented in the balance sheets.

SPS employs additionalcredit risk controlmechanisms when appropriate, such as letters ofcredit, parental guarantees, standardized master netting agreements and termination provisions that allowfor offsetting of positive and

negative exposures. Credit exposure is monitored and, when necessary, the activity with a specific counterparty is limited untilcredit enhancement is provided.

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SPS’most significant concentrations ofcredit riskwith particularentities or industries are contracts with counterparties to its wholesale, trading and non-trading commodity and transmission activities. At June 30, 2015, one of SPS’

eight most significant counterparties for these activities,comprising $9.6million or 9 percent of this credit exposure, had investment grade credit ratings fromStandard &Poor’s Ratings Services, Moody’s Investor Services or Fitch Ratings. Sixof the eight most significant counterparties,comprising $58.5million or 54 percent of this credit exposure, were not rated by these agencies, but based on SPS’ internalanalysis, had credit quality consistent with investment

grade. Another of these significant counterparties,comprising $1.3million or 1 percent of this credit exposure, had credit quality less than investment grade, based on SPS’ internalanalysis. Alleight of these significant counterparties

are RTOs, municipal orcooperative electric entities or other utilities.

Recurring Fair Value Measurements —The following table presents foreach of the fair value hierarchy levels, SPS’ derivative assets and liabilities measured at fair value on a recurring basis at June 30, 2015:

June 30, 2015

Fair Value

(Thousands of Dollars) Level 1 Level 2 Level 3 Fair Value Total Counterparty Netting Total

Current derivative assets

Other derivative instruments:

Electric commodity $ — $ — $ 21,533 $ 21,533 $ (10,070) $ 11,463

Totalcurrent derivative assets $ — $ — $ 21,533 $ 21,533 $ (10,070) 11,463

PPAs 7,892

Current derivative instruments $ 19,355

Noncurrent derivative assets

PPAs $ 29,218

Noncurrent derivative instruments $ 29,218

Current derivative liabilities

Other derivative instruments:

Electric commodity $ — $ — $ 10,070 $ 10,070 $ (10,070) $ —

Totalcurrent derivative liabilities $ — $ — $ 10,070 $ 10,070 $ (10,070) —

PPAs 3,565

Current derivative instruments $ 3,565

Noncurrent derivative liabilities

PPAs $ 28,860

Noncurrent derivative instruments $ 28,860

In 2003, asaresult of implementing newguidance on the normal purchaseexception for derivativeaccounting, SPSbegan recording several long-termPPAsat fair value dueto accounting requirementsrelated to underlying priceadjustments. Asthese purchasesare

recovered through normal regulatory recovery mechanismsin therespectivejurisdictions, thechangesin fair valuefor thesecontractswere offset by regulatory assetsand liabilities. During 2006, SPSqualified thesecontracts under the normal purchaseexception.

Based on this qualification, thecontractsare no longer adjusted to fair valueand the previouscarrying value of thesecontractswill beamortized over theremaining contract livesalongwith the offsetting regulatory assetsand liabilities.

SPSnets derivativeinstrumentsand related collateral in its balancesheet when supported by alegally enforceablemaster netting agreement, and all derivativeinstrumentsand related collateralamountsweresubject to master netting agreementsat June 30, 2015. At

June 30, 2015, derivativeassetsand liabilitiesinclude no obligationsto return cash collateral or rightsto reclaimcash collateral. Thecounterparty netting amounts presented excludesettlement receivablesand payablesand non-derivativeamountsthat may be

subject to thesamemaster netting agreements.

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The following table presents foreach of the fair value hierarchy levels, SPS’ derivative assets and liabilities measured at fair value on a recurring basis at Dec. 31, 2014:

Dec. 31, 2014

Fair Value

(Thousands of Dollars) Level 1 Level 2 Level 3 Fair Value Total Counterparty Netting Total

Current derivative assets

Other derivative instruments:

Electric commodity $ — $ — $ 25,774 $ 25,774 $ (9,890) $ 15,884

Totalcurrent derivative assets $ — $ — $ 25,774 $ 25,774 $ (9,890) 15,884

PPAs 7,892

Current derivative instruments $ 23,776

Noncurrent derivative assets

PPAs $ 33,164

Noncurrent derivative instruments $ 33,164

Current derivative liabilities

Other derivative instruments:

Electric commodity $ — $ — $ 9,890 $ 9,890 $ (9,890) $ —

Totalcurrent derivative liabilities $ — $ — $ 9,890 $ 9,890 $ (9,890) —

PPAs 3,565

Current derivative instruments $ 3,565

Noncurrent derivative liabilities

PPAs $ 30,643

Noncurrent derivative instruments $ 30,643

In 2003, asaresult of implementing newguidance on the normal purchaseexception for derivativeaccounting, SPSbegan recording several long-termPPAsat fair value dueto accounting requirementsrelated to underlying priceadjustments. Asthese purchasesare

recovered through normal regulatory recovery mechanismsin therespectivejurisdictions, thechangesin fair valuefor thesecontractswere offset by regulatory assetsand liabilities. During 2006, SPSqualified thesecontracts under the normal purchaseexception.

Based on this qualification, thecontractsare no longer adjusted to fair valueand the previouscarrying value of thesecontractswill beamortized over theremaining contract livesalongwith the offsetting regulatory assetsand liabilities.

SPSnets derivativeinstrumentsand related collateral in its balancesheet when supported by alegally enforceablemaster netting agreement, and all derivativeinstrumentsand related collateralamountsweresubject to master netting agreementsat Dec. 31, 2014. At Dec. 31, 2014, derivativeassetsand liabilitiesinclude no obligationsto return cash collateral or rightsto reclaimcash collateral. Thecounterparty netting amounts presented excludesettlement receivablesand payablesand non-derivativeamountsthat may be

subject to thesamemaster netting agreements.

The following table presents the changes in Level 3 commodity derivatives for the three and sixmonths ended June 30, 2015 and 2014:

Three Months Ended June 30

(Thousands of Dollars) 2015 2014

Balance at April 1 $ 6,457 $ 5,791

Purchases 17,284 38,419

Settlements (10,022) (13,554

Net transactions recorded during the period:

(Losses) Gains recognized as regulatory assets and liabilities (2,256) 3,286

Balance at June 30 $ 11,463 $ 33,942

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Six Months Ended June 30

(Thousands of Dollars) 2015 2014

Balance at Jan. 1 $ 15,884 $ 9,933

Purchases 22,213 39,475

Settlements (18,400) (14,655

Net transactions recorded during the period:

Losses recognized as regulatory assets and liabilities (8,234) (811

Balance at June 30 $ 11,463 $ 33,942

SPS recognizes transfers between levels as of the beginning ofeach period. There were no transfers ofamounts between levels for derivative instruments for the three and sixmonths ended June 30, 2015 and 2014.

Fair Value of Long-TermDebt

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

June 30, 2015 Dec. 31, 2014

(Thousands of Dollars)

Carrying Amount Fair ValueCarrying Amount Fair Value

Long-termdebt, including current portion $ 1,349,858 $ 1,491,780 $ 1,349,691 $ 1,572,414

The fair value of SPS’ long-termdebt is estimated based on recent trades and observable spreads frombenchmark interest rates forsimilarsecurities. The fair value estimates are based on information available to management as of

June 30, 2015 and Dec. 31, 2014,and given the observability of the inputs to these estimates, the fair values presented for long-termdebt have been assigned a Level 2.

9. Other Income (Expense), Net

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

Three Months Ended June 30 Six Months Ended June 30

(Thousands of Dollars) 2015 2014 2015 2014

Interest income $ 13 $ 53 $ 45 $ 240

Other nonoperating income 65 2 110 —

Insurance policy income (expense) 78 (184) (55) (328

Other income (expense), net $ 156 $ (129) $ 100 $ (88

10. Benefit Plans andOther Postretirement Benefits

Components of Net Periodic Benefit Cost (Credit)

Three Months Ended June 30

2015 2014 2015 2014

(Thousands of Dollars) Pension Benefits

Postretirement Health Care Benefits

Service cost $ 2,751 $ 2,296 $ 238 $ 311

Interest cost 5,046 5,111 437 643

Expected return on plan assets (7,152) (6,545) (635) (811

Amortization of priorservice cost (credit) 10 13 (100) (101

Amortization of net loss (gain) 3,772 3,331 (160) (81

Net periodic benefit cost (credit) 4,427 4,206 (220) (39

Credits recognized due to the effects of regulation 686 708 — —

Net benefit cost (credit) recognized for financial reporting $ 5,113 $ 4,914 $ (220) $ (39

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Six Months Ended June 30

2015 2014 2015 2014

(Thousands of Dollars) Pension Benefits

Postretirement Health Care Benefits

Service cost $ 5,503 $ 4,592 $ 477 $ 623

Interest cost 10,092 10,222 873 1,286

Expected return on plan assets (14,305) (13,090) (1,270) (1,623

Amortization of priorservice cost (credit) 20 27 (200) (201

Amortization of net loss (gain) 7,544 6,663 (320) (161

Net periodic benefit cost (credit) 8,854 8,414 (440) (76

Credits recognized due to the effects of regulation 1,399 1,415 — —

Net benefit cost (credit) recognized for financial reporting $ 10,253 $ 9,829 $ (440) $ (76

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

11. Other Comprehensive Income

Changes in accumulated othercomprehensive loss, net of tax, for the three and sixmonths ended June 30, 2015 and 2014were as follows:

Gains and Losses on Cash Flow Hedges

(Thousands of Dollars) Three Months Ended June 30, 2015 Three Months Ended June 30, 2014

Accumulated othercomprehensive loss at April 1 $ (947) $ (1,118)

Losses reclassified fromnet accumulated othercomprehensive loss 43 42

Net current period othercomprehensive income 43 42

Accumulated othercomprehensive loss at June 30 $ (904) $ (1,076)

Gains and Losses on Cash Flow Hedges

(Thousands of Dollars) Six Months Ended June 30, 2015 Six Months Ended June 30, 2014

Accumulated othercomprehensive loss at Jan. 1 $ (989) $ (1,161)

Losses reclassified fromnet accumulated othercomprehensive loss 85 85

Net current period othercomprehensive income 85 85

Accumulated othercomprehensive loss at June 30 $ (904) $ (1,076)

Reclassifications fromaccumulated othercomprehensive loss for the three and sixmonths ended June 30, 2015 and 2014were as follows:

Amounts Reclassified from

Accumulated Other Comprehensive Loss

(Thousands of Dollars) Three Months Ended June 30, 2015 Three Months Ended June 30, 2014

Losses on cash flowhedges:

Interest rate derivatives $ 67 $ 66

Total, pre-tax 67 66

Taxbenefit (24) (24)

Totalamounts reclassified, net of tax $ 43 $ 42

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Amounts Reclassified from

Accumulated Other Comprehensive Loss

(Thousands of Dollars) Six Months Ended June 30, 2015 Six Months Ended June 30, 2014

Losses on cash flowhedges:

Interest rate derivatives $ 133 $ 133

Total, pre-tax 133 133

Taxbenefit (48) (48)

Totalamounts reclassified, net of tax $ 85 $ 85

Included in interest charges.

Item2 — MANAGEMENT’S DISCUSSIONANDANALYSIS OFFINANCIALCONDITIONANDRESULTS OFOPERATIONS

Discussion of financialcondition and liquidity for SPS is omitted perconditions set forth in general instructions H(1) (a)and (b) of Form10-Qfor 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 Form10-Qfor wholly owned subsidiaries (reduced disclosure format).

Financial Review

The following discussion and analysis by management focuses on those factors that had a materialeffect on SPS’ financialcondition, results of operations,and cash flows during the periods presented, orare expected to have a material impact in the future. It should be read in conjunction with the accompanying unaudited financialstatements and the related notes to the financialstatements. Due to the seasonality of SPS’electric sales, such interimresults are

not necessarily an appropriate base fromwhich to project annual results.

Forward-Looking Statements

Except for the historicalstatements contained in this report, the matters discussed in the following discussion and analysis are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forwardlooking statements are intended to be identified in this document by the words “anticipate,” “believe,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should” and similar

expressions. Actual results may vary materially. Forward-looking statements speak only as of the date they are made,and we do not undertake any obligation to update themto reflect changes that occurafter that date. Factors that

could cause actual results to differmaterially include, but are not limited to: generaleconomic conditions, including inflation rates, monetary fluctuations and their impact on capitalexpenditures and the ability of SPS to obtain financing

on favorable terms; business conditions in the energy industry, including the risk ofa slowdown in the U.S.economy or delay in growth recovery; trade, fiscal, taxation and environmental policies in areas where SPS has a financial

interest; customer business conditions; actions ofcredit rating agencies; competitive factors, including the extent and timing of the entry ofadditionalcompetition in the markets served by SPS; unusualweather; effects of geopolitical

events, including warand acts of terrorism; cybersecurity threats and data security breaches; state, federaland 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 environmentalcompliance conditions; structures that affect the speed and degree to which competition enters the electric market; costs and othereffects of legaland administrative

proceedings, settlements, investigations and claims; financial or regulatory accounting policies imposed by regulatory bodies; availability orcost ofcapital; employee work force factors; and the other risk factors listed fromtime to time

by SPS in reports filed with the SEC, including Risk Factors in Item1A of SPS’ Form10-Kfor the yearended Dec. 31, 2014,and Item1A and Exhibit 99.01 to this Quarterly Report on Form10-Qfor the quarterended June 30, 2015.

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Results ofOperations

SPS’ net income was approximately $42.8million for the sixmonths ended June 30, 2015,compared with net income ofapproximately $46.8million for the same period in 2014. Higherelectric rates in Texas were offset by higher operating

and maintenance (O&M)expenses, depreciation,and lower AFUDC,along with the impact of unfavorable weather.

Electric Revenues andMargin

Electric fueland purchased powerexpenses tend to vary with changing retailand wholesale sales requirements and unit cost changes in fueland purchased power. The design of fueland purchased powercost recovery mechanisms of

the Texas and NewMexico jurisdictions may not allowforcomplete recovery ofallexpenses and, therefore,changes in fuel or purchased powercosts can impact earnings. The following tables detail the electric revenues and margin:

Six Months Ended June 30

(Millions of Dollars) 2015 2014

Electric revenues $ 847 $ 941

Electric fueland purchased power (489) (603

Electric margin $ 358 $ 338

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

Electric Revenues

(Millions of Dollars) 2015 vs. 2014

Fueland purchased powercost recovery $ (149

Estimated impact of weather (7

Trading 25

Retail rate increases (Texas) 19

Transmission revenue 15

Other, net 3

Total decrease in electric revenues $ (94

Electric Margin

(Millions of Dollars) 2015 vs. 2014

Retail rate increases (Texas) $ 19

Transmission revenue, net ofcosts 8

Fuel recovery 3

Estimated impact of weather (7

Fuel handling and procurement (4

Other, net 1

Total increase in electric margin $ 20

Non-Fuel Operating Expense andOther Items

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

(Millions of Dollars) 2015 vs. 2014

Employee benefits $ 3

Plant generation costs 2

Distribution cost increases 1

Other, net 3

Total increase in O&M expenses $ 9

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

expansion.

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

property taxes.

Allowancefor FundsUsed During Construction (AFUDC)— AFUDCdecreased $4.7million for the sixmonths ended June 30, 2015 compared with the same period in 2014. The decrease is primarily due to the decrease of transmission

facilities construction.

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

lower interest rates.

Income Taxes — Income taxexpense decreased $2.3million for the sixmonths ended June 30, 2015 compared with the same period in 2014. The decrease in income taxexpense is primarily due to lower pre-taxearnings, partially offset by

decreased permanent plant-related adjustments in 2015. The ETRwas 35.8 percent for the sixmonths ended June 30, 2015,compared with 35.9 percent for the same period in 2014.

Public UtilityRegulation

Except to the extent noted below, the circumstances set forth in Public Utility Regulation included in Item1. of SPS' Annual Report on Form10-Kfor the yearended Dec. 31, 2014,and Public Utility Regulation included in Item2. of SPS' Quarterly Report on Form10-Qfor the quarterly period ended March 31, 2015,appropriately represent, in allmaterial respects, the current status of public utility regulation,and are incorporated herein by reference.

Texas Legislation— In June 2015, the Texas Governorsigned HB1535 into law. As a result, SPSmay reduce regulatory lag through earlier inclusion ofcertain capitaladditions in rate base as wellas expediting the implementation of

newrates. Key provisions of the billare as follows:

• Utilities may include actualand estimated post-test yearcapitaladditions up through 30-days before the filing date;

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

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

• Establishes time limits for the PUCT to rule on a newgeneration plant request fora certificate ofconvenience and necessity.

Summary of Recent Federal RegulatoryDevelopments

The FERChas jurisdiction over rates forelectric transmission service in interstate commerce and electricity sold at wholesale,asset transactions and mergers,accounting practices and certain otheractivities of SPS, including

enforcement of North American Electric Reliability Corporation mandatory electric reliability standards. State and localagencies have jurisdiction overmany 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 Form10-Kfor the yearended Dec. 31, 2014. In addition to the matters

discussed below, see Note 5 to the financialstatements fora discussion of other regulatory matters.

FERCOrder,New ROE Policy — In June 2014, the FERCadopted a newtwo-step ROEmethodology forelectric utilities. The issue of howto apply the newFERCROEmethodology is being contested in various complaint

proceedings. FERCis not expected to issue orders in any of the ROEcomplaint proceedings until 2016. See Note 5 to the consolidated financialstatements for discussion of the Wholesale Rate complaints.

Item4 — CONTROLS ANDPROCEDURES

Disclosure Controls andProcedures

SPSmaintains a set of disclosure controls and procedures designed to ensure that information required to be disclosed in the reports that it files orsubmits under the Securities Exchange Act of 1934 is recorded, processed, summarized,

and reported within the time periods specified in SECrules and forms. In addition, the disclosure controls and procedures ensure that information required to be disclosed is accumulated and communicated to management, including

the chiefexecutive officer (CEO)and chief financial officer (CFO),allowing timely decisions regarding required disclosure. As ofJune 30, 2015, based on an evaluation carried out under the supervision and with the participation of SPS’ management, including the CEOand CFO, of the effectiveness of its disclosure controls and the procedures, the CEOand CFOhave concluded that SPS’ disclosure controls and procedures were effective.

Internal Control Over Financial Reporting

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

PartII— OTHERINFORMATION

Item1 — LEGALPROCEEDINGS

SPS is involved in various litigation matters that are being defended and handled in the ordinary course of business. The assessment of whethera loss is probable or is a reasonable possibility,and whether the loss ora range of loss is

estimable, often involves a series ofcomplexjudgments about future events. Management maintains accruals forsuch losses that are probable of being incurred and subject to reasonable estimation. Management is sometimes unable

to estimate an amount or range ofa 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 ofsuch matters, including a possible eventual loss.

Additional Information

See Note 6 to the financialstatements for further discussion of legalclaims and environmental proceedings. See Note 5 to the financialstatements for discussion of proceedings involving utility rates and other regulatory matters.

Item1A — RISKFACTORS

SPS’ risk factors are documented in Item1A of Part I of its Annual Report on Form10-Kfor the yearended Dec. 31, 2014, which is incorporated herein by reference. There have been no materialchanges fromthe risk factors previously

disclosed in the Form10-K.

Item4 — MINESAFETYDISCLOSURES

None.

Item5 — OTHERINFORMATION

None.

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Item6 — EXHIBITS

* Indicates incorporation by reference

3.01* Amended and Restated Articles of Incorporation of SPS dated Sept. 30, 1997 (Exhibit 3(a)(2) to Form10-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 Form10-Q/A for the quarterended Sept. 30, 2013 (file no. 001-03789)).

31.01 Principal Executive Officer’s certifications pursuant to 18U.S.C. Section 1350,as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.02 Principal FinancialOfficer’s certifications pursuant to 18U.S.C. Section 1350,as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.01 Certification pursuant to 18U.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 ReformAct of 1995.

101 The following materials fromSPS’ Quarterly Report on Form10-Qfor the quarterended June 30, 2015 are formatted in XBRL(eXtensible Business Reporting Language): (i) the Statements of Income, (ii) the Statements of

Comprehensive Income (iii) the Statements of Cash Flows, (iv) the Balance Sheets, (v) Notes to Financial Statements,and (vi) document and entity information.

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SIGNATURES

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

Southwestern Public Service Company

Aug. 3, 2015 By: /s/ JEFFREYS. SAVAGE

Jeffrey S. Savage

Senior Vice President, Controller

(PrincipalAccounting Officer)

/s/ TERESA S. MADDEN

Teresa S. Madden

Executive Vice President, Chief FinancialOfficerand Director

(Principal FinancialOfficer)

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