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 September 30, 2011

or

o 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 o 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 o 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 o	Accelerated filer o
Non-accelerated filer x	Smaller reporting company o
(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).   o 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 Oct. 31, 2011
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	17
Item 4	—	Controls and Procedures	21
PART II — OTHER INFORMATION
Item 1	—	Legal Proceedings	21
Item 1A	—	Risk Factors	21
Item 6	—	Exhibits	22
SIGNATURES			23
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.  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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PART 1 — FINANCIAL INFORMATION

Item 1 — FINANCIAL STATEMENTS

SOUTHWESTERN PUBLIC SERVICE COMPANY

STATEMENTS OF INCOME (UNAUDITED)

(amounts in thousands of dollars)

	Three Months Ended Sept. 30,						Nine Months Ended Sept. 30,
	2011			2010			2011			2010
Operating revenues	$	522,921		$	467,424		$	1,337,419		$	1,247,355
Operating expenses
Electric fuel and purchased power		325,930			288,386			850,583			788,089
Other operating and maintenance expenses		61,651			61,807			187,136			180,794
Demand side management program expenses		4,658			3,393			12,469			8,386
Depreciation and amortization		27,067			26,083			79,589			77,391
Taxes (other than income taxes)		10,730			10,818			31,825			30,879
Total operating expenses		430,036			390,487			1,161,602			1,085,539
Operating income		92,885			76,937			175,817			161,816
Other income (expense), net		286			(82	)		432			31
Allowance for funds used during construction – equity		894			1,085			4,178			2,529
Interest charges and financing costs
Interest charges – includes other financing costs of $763, $666, $2,188 and $1,975, respectively		16,456			16,217			48,322			48,099
Allowance for funds used during construction – debt		(655	)		(792	)		(3,022	)		(2,052	)
Total interest charges and financing costs		15,801			15,425			45,300			46,047
Income before income taxes		78,264			62,515			135,127			118,329
Income taxes		29,683			23,326			51,636			47,045
Net income	$	48,581		$	39,189		$	83,491		$	71,284

See Notes to Financial Statements

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SOUTHWESTERN PUBLIC SERVICE COMPANY

STATEMENTS OF CASH FLOWS (UNAUDITED)

(amounts in thousands of dollars)

	Nine Months Ended Sept. 30,
	2011			2010
Operating activities
Net income	$	83,491		$	71,284
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization		81,253			79,094
Demand side management program amortization		1,358			1,573
Deferred income taxes		56,476			26,520
Amortization of investment tax credits		(255	)		(223	)
Allowance for equity funds used during construction		(4,178	)		(2,529	)
Net realized and unrealized hedging and derivative transactions		201			201
Changes in operating assets and liabilities:
Accounts receivable		(37,089	)		(25,352	)
Accrued unbilled revenues		(3,013	)		(12,666	)
Inventories		(4,732	)		(5,734	)
Prepayments and other		(1,655	)		11,468
Accounts payable		(6,129	)		(19,399	)
Net regulatory assets and liabilities		7,327			(19,274	)
Other current liabilities		17,530			16,240
Change in other noncurrent assets		1,101			(2,838	)
Change in other noncurrent liabilities		(11,223	)		(2,111	)
Net cash provided by operating activities		180,463			116,254
Investing activities
Utility capital/construction expenditures		(224,864	)		(196,035	)
Allowance for equity funds used during construction		4,178			2,529
Investments in utility money pool arrangement		-			(204,200	)
Repayments from utility money pool arrangement		-			281,200
Other investments		221			-
Net cash used in investing activities		(220,465	)		(116,506	)
Financing activities
Repayment of short-term borrowings, net		(49,000	)		-
Proceeds from issuance of long-term debt		193,149			-
Repayment of long-term debt		(101,800	)		(25,000	)
Borrowings under utility money pool arrangement		283,500			61,000
Repayments under utility money pool arrangement		(283,500	)		-
Capital contributions from parent		90,000			8,802
Dividends paid to parent		(64,401	)		(50,810	)
Net cash provided by (used in) financing activities		67,948			(6,008	)
Net increase (decrease) in cash and cash equivalents		27,946			(6,260	)
Cash and cash equivalents at beginning of period		1,778			7,363
Cash and cash equivalents at end of period	$	29,724		$	1,103
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	(30,927	)	$	(43,963	)
Cash paid for income taxes, net		(192	)		(8,310	)
Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable	$	7,012		$	4,075

See Notes to Financial Statements

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SOUTHWESTERN PUBLIC SERVICE COMPANY

BALANCE SHEETS (UNAUDITED)

(amounts in thousands of dollars)

	Sept. 30, 2011			Dec. 31, 2010
Assets
Current assets
Cash and cash equivalents	$	29,724		$	1,778
Accounts receivable, net		79,398			44,871
Accounts receivable from affiliates		4,172			1,610
Accrued unbilled revenues		113,197			110,184
Inventories		34,581			29,849
Regulatory assets		29,138			21,547
Derivative instruments		7,892			7,892
Deferred income taxes		18,988			19,051
Prepayments and other		6,661			5,006
Total current assets		323,751			241,788
Property, plant and equipment, net		2,532,454			2,401,266
Other assets
Regulatory assets		273,338			283,207
Derivative instruments		58,814			64,734
Other		12,431			10,668
Total other assets		344,583			358,609
Total assets	$	3,200,788		$	3,001,663
Liabilities and Equity
Current liabilities
Current portion of long-term debt	$	-		$	44,500
Short-term debt		-			49,000
Accounts payable		133,173			134,322
Accounts payable to affiliates		10,780			24,525
Regulatory liabilities		62,252			53,197
Taxes accrued		22,940			19,867
Accrued interest		25,155			12,128
Dividends payable		-			16,358
Derivative instruments		3,601			3,601
Other		27,786			21,349
Total current liabilities		285,687			378,847
Deferred credits and other liabilities
Deferred income taxes		598,220			541,204
Deferred investment tax credits		1,796			2,051
Regulatory liabilities		116,818			134,952
Asset retirement obligations		22,195			21,131
Derivative instruments		42,291			44,991
Pension and employee benefit obligations		47,606			52,280
Other		5,279			10,827
Total deferred credits and other liabilities		834,205			807,436
Commitments and contingent liabilities
Capitalization
Long-term debt		993,208			853,267
Common stock – authorized 200 shares of $1.00 par value; outstanding 100 shares		-			-
Additional paid in capital		783,531			693,531
Retained earnings		305,704			270,257
Accumulated other comprehensive loss		(1,547	)		(1,675	)
Total common stockholder's equity		1,087,688			962,113
Total liabilities and equity	$	3,200,788		$	3,001,663

See Notes to Financial Statements

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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 Sept. 30, 2011, and Dec. 31, 2010; the results of its operations for the three and nine months ended Sept. 30, 2011 and 2010; and its cash flows for the nine months ended Sept. 30, 2011 and 2010.  All adjustments are of a normal, recurring nature, except as otherwise disclosed.  Management has also evaluated the impact of events occurring after Sept. 30, 2011 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, 2010 balance sheet information has been derived from the audited 2010 financial statements included in the SPS Annual Report on Form 10-K for the year ended Dec. 31, 2010.  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, 2010, filed with the SEC on Feb. 28, 2011.  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, 2010, appropriately represent, in all material respects, the current status of accounting policies and are incorporated herein by reference.

2. Accounting Pronouncements

Recently Issued

Fair Value Measurement — In May 2011, the Financial Accounting Standards Board (FASB) issued Fair Value Measurement (Topic 820) — Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs (Accounting Standards Update (ASU) No. 2011-04), which provides additional guidance for fair value measurements.  These updates to the FASB Accounting Standards Codification (Codification) include clarifications regarding existing fair value measurement principles and disclosure requirements, and also specific new guidance for items such as measurement of instruments classified within stockholders’ equity and disclosures regarding the sensitivity of Level 3 measurements to changes in valuation model inputs.  These updates to the Codification are effective for interim and annual periods beginning after Dec. 15, 2011.  SPS does not expect the implementation of this guidance to have a material impact on its financial statements.

Comprehensive Income — In June 2011, the FASB issued Comprehensive Income (Topic 220) — Presentation of Comprehensive Income (ASU No. 2011-05), which updates the Codification to require the presentation of the components of net income, the components of other comprehensive income and total comprehensive income in either a single continuous statement of comprehensive income or in two separate, but consecutive statements of net income and comprehensive income.  These updates do not affect the items reported in other comprehensive income or the guidance for reclassifying such items to net income.  These updates to the Codification are effective for interim and annual periods beginning after Dec. 15, 2011.  SPS does not expect the implementation of this presentation guidance to have a material impact on its financial statements.

Multiemployer Plans — In September 2011, the FASB issued Multiemployer Plans (Subtopic 715-80) — Disclosures about an Employer’s Participation in a Multiemployer Plan (ASU No. 2011-09), which updates the Codification to require certain disclosures about an entity’s involvement with multiemployer pension and other postretirement benefit plans.  These updates do not affect recognition and measurement guidance for an employer’s participation in multiemployer plans, but rather require additional disclosure such as the nature of multiemployer plans and the employer’s participation, contributions to the plans and details regarding significant plans.  These updates to the Codification are effective for annual periods ending after Dec. 15, 2011.  SPS does not expect the implementation of this disclosure guidance to have a material impact on its financial statements.

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3. Selected Balance Sheet Data

(Thousands of Dollars)	Sept. 30, 2011			Dec. 31, 2010
Accounts receivable, net
Accounts receivable	$	84,562		$	49,966
Less allowance for bad debts		(5,164	)		(5,095	)
	$	79,398		$	44,871
Inventories
Materials and supplies	$	16,499		$	15,093
Fuel		18,082			14,756
	$	34,581		$	29,849
Property, plant and equipment, net
Electric plant	$	4,092,782		$	3,826,202
Construction work in progress		135,758			221,025
Total property, plant and equipment		4,228,540			4,047,227
Less accumulated depreciation		(1,696,086	)		(1,645,961	)
	$	2,532,454		$	2,401,266

4. Income Taxes

Except to the extent noted below, the circumstances set forth in Note 6 to the financial statements included in SPS’ Annual Report on Form 10-K for the year ended Dec. 31, 2010 appropriately represent, in all material respects, the current status of other income tax matters, and are incorporated herein by reference.

Federal Audit — SPS is a member of the Xcel Energy affiliated group that files a consolidated federal income tax return.  The statute of limitations applicable to Xcel Energy’s 2007 federal income tax return expired in September 2011.  The statute of limitations applicable to Xcel Energy’s 2008 federal income tax return expires in September 2012.  The Internal Revenue Service (IRS) commenced an examination of tax years 2008 and 2009 in the third quarter of 2010.  As of Sept. 30, 2011, the IRS had not proposed any material adjustments to tax years 2008 and 2009.

State Audits — SPS is a member of the Xcel Energy affiliated group that files consolidated state income tax returns. As of Sept. 30, 2011, SPS’ earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations was 2007.  As of Sept. 30, 2011, there were no state income tax audits in progress.

Unrecognized Tax Benefits — The unrecognized tax benefit balance includes permanent tax positions, which if recognized would affect the annual effective tax rate (ETR). In addition, the unrecognized tax benefit balance includes temporary tax positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. A change in the period of deductibility would not affect the ETR but would accelerate the payment of cash to the taxing authority to an earlier period.

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

(Millions of Dollars)	Sept. 30, 2011		Dec. 31, 2010
Unrecognized tax benefit — Permanent tax positions	$	0.2	$	0.2
Unrecognized tax benefit — Temporary tax positions		3.7		4.1
Unrecognized tax benefit balance	$	3.9	$	4.3

The decrease in the unrecognized tax benefit balance for the nine months ended Sept. 30, 2011 of $0.4 million was due primarily to adjustments for prior year’s activity.  SPS’ amount of unrecognized tax benefits could significantly change in the next 12 months as the IRS audit progresses and state audits resume.  As the IRS examination moves closer to completion, it is reasonably possible that the amount of unrecognized tax benefits could decrease by up to approximately $3 million

The payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with net operating loss and tax credit carryforwards.  The payables for interest related to unrecognized tax benefits at Sept. 30, 2011 and Dec. 31, 2010 were not material.  No amounts were accrued for penalties related to unrecognized tax benefits as of Sept. 30, 2011 or Dec. 31, 2010.

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5. Rate Matters

Except to the extent noted below, the circumstances set forth in Note 11 to the financial statements included in SPS’ Annual Report on Form 10-K for the year ended Dec. 31, 2010 appropriately represent, in all material respects, the current status of other rate matters, and are incorporated herein by reference.

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

SPS New Mexico Electric Rate Case — In February 2011, SPS filed a request in New Mexico with the NMPRC seeking to increase New Mexico electric rates approximately $19.9 million.  The rate filing was based on a 2011 test year adjusted for known and measurable changes for 2012, a requested return on equity of 11.25 percent, an electric rate base of $390.3 million and an equity ratio of 51.11 percent.

In September 2011, the parties filed an unopposed black box settlement to resolve all issues in the case.  If the settlement is approved by the NMPRC, base rates will increase by $13.5 million.  SPS has agreed not to file another base rate case until Dec. 3, 2012 with new final rates from the result of such case not going into effect until Jan. 1, 2014 (Settlement Period), provided however, that SPS can request to implement interim rates if the NMPRC standard for interim rates is met.  During the Settlement Period, rates are to remain fixed aside from the continued operation of the fuel adjustment clause and certain exceptions for energy efficiency, a rider for an approved renewable portfolio standard regulatory asset, and actual costs incurred for environmental regulations with an effective date after Dec. 31, 2010.

In October 2011, the NMPRC held hearings on the settlement.  A decision by the NMPRC is expected by year-end and final rates are expected to be implemented effective Jan. 1, 2012.

6. Commitments and Contingent Liabilities

Except to the extent noted below and in Note 5 to the financial statements in this Quarterly Report on Form 10-Q, the circumstances set forth in Notes 11 and 12 to the financial statements in SPS’ Annual Report on Form 10-K for the year ended Dec. 31, 2010, 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.

Commitments

Variable Interest Entities— The accounting guidance for consolidation of variable interest entities requires enterprises to consider the activities that most significantly impact an entity’s financial performance, and power to direct those activities, when determining whether an enterprise is a variable interest entity’s primary beneficiary.

Purchased Power Agreements — Under certain purchased power agreements, 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.

SPS has evaluated each of these variable interest entities for possible consolidation, including review of qualitative factors such as the length and terms of the contract, control over operating and maintenance (O&M) expenses, historical and estimated future fuel and electricity prices, and financing activities.  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.  SPS had approximately 1,027 megawatts (MW) of capacity under long-term purchased power agreements as of Sept. 30, 2011 and Dec. 31, 2010 with entities that have been determined to be variable interest entities.  These agreements have expiration dates through the year 2033.

Guarantees — In connection with its Lubbock sale agreement in 2010, SPS provides for indemnification to the counterparty for liabilities incurred as a result of a breach of a representation or warranty by the indemnifying party.  These indemnification obligations generally have a discrete term and are intended to protect the parties against risks that are difficult to predict or impossible to quantify at the time of the consummation of a particular transaction.

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The following table presents guarantees issued and outstanding for SPS:

(Millions of Dollars)	Sept. 30, 2011		Dec. 31, 2010
Guarantees issued and outstanding (a)	$	87.0	$	87.0

(a) SPS has provided indemnification to Lubbock for losses arising out of any breach of the representations, warranties and covenants under the related asset purchase agreement and for losses arising out of certain other matters, including pre-closing unknown liabilities.  The indemnification provisions are capped at the purchase price, $87 million, in the aggregate.  As of Sept. 30, 2011 and Dec. 31, 2010, no claims have been made.  The indemnification provisions for most representations and warranties expire 12 months after the closing date.  Certain representations and warranties, including those having to do with transaction authorization survive indefinitely.  The indemnification for covenants survives until the applicable covenant is performed.

Environmental Contingencies

SPS has been, or is currently, involved with the cleanup of contamination from certain hazardous substances at several sites.  In many situations, SPS believes it will recover some portion of these costs through insurance claims.  Additionally, where applicable, SPS is pursuing, or intends to pursue, recovery from other potentially responsible parties (PRPs) and through the rate regulatory process.  New and changing federal and state environmental mandates can also create added financial liabilities for SPS, which are normally recovered through the rate regulatory process.  To the extent any costs are not recovered through the options listed above, SPS would be required to recognize an expense.

Site Remediation — The Comprehensive Environmental Response, Compensation and Liability Act of 1980 and comparable state laws impose liability, without regarding the legality of the original conduct, on certain classes of persons responsible for the release of hazardous substances to the environment. SPS must pay all or a portion of the cost to remediate sites where past activities of SPS or other parties have caused environmental contamination.  Environmental contingencies could arise from various situations, including third party sites, for which SPS is alleged to be a PRP that sent hazardous materials and wastes.  At Sept. 30, 2011 and Dec. 31, 2010, the liability for the cost of remediating these sites was estimated to be $0.1 million.

Asbestos Removal — Some of SPS’ facilities contain asbestos.  Most asbestos will remain undisturbed until the facilities that contain it are demolished or removed.  SPS has recorded an estimate for final removal of the asbestos as an asset retirement obligation.  See additional discussion of asset retirement obligations in Note 12 of the SPS Annual Report on Form 10-K for the year ended Dec. 31, 2010.  It may be necessary to remove some asbestos to perform maintenance or make improvements to other equipment.  The cost of removing asbestos as part of other work is not expected to be material and is recorded as incurred as operating expenses for maintenance projects, capital expenditures for construction projects or removal costs for demolition projects.

Other Environmental Requirements

Environmental Protection Agency (EPA) Greenhouse Gas (GHG) Regulation — In December 2009, the EPA issued its “endangerment” finding that GHG emissions endanger public health and welfare.  In January 2011, new EPA permitting requirements became effective for GHG emissions of new and modified large stationary sources, which are applicable to the construction of new power plants or power plant modifications that increase emissions above a certain threshold.

GHG New Source Performance Standard Proposal — The EPA plans to propose GHG regulations applicable to emissions from new and existing power plants under the Clean Air Act (CAA).  The EPA had planned to release its proposal in September 2011, but has delayed it without establishing a new proposal date.

Cross State Air Pollution Rule (CSAPR) — On July 7, 2011, the EPA issued its CSAPR.  The rule, previously called the Clean Air Transport Rule (CATR), addresses long range transport of particulate matter and ozone by requiring reductions in sulfur dioxide (SO2) and nitrogen oxide (NOx) from utilities located in the eastern half of the U.S., including Texas.  The CSAPR sets more stringent requirements than the proposed CATR and, in contrast to that proposal, specifically requires plants in Texas to reduce their SO2 and annual NOx emissions.  The rule creates an emissions trading program.  SPS may comply by reducing emissions and/or purchasing allowances.  The CSAPR is a final rule and requires compliance beginning in 2012.

9

At this time, SPS believes that the CSAPR will ultimately require the installation of additional emission controls on some of SPS’ coal-fired electric generating units.  SPS is still evaluating compliance options, however SPS believes the cost of any required capital investment will be recoverable from customers.  Because the CSAPR requires compliance in 2012, SPS will be required to take additional short-term action, including redispatching its system to reduce coal plant operating hours, in order to decrease emissions from its facilities prior to the installation of emission controls.  Texas was not included in the annual SO2 and NOx reductions requirements of the proposed rule.  Without additional notice, the EPA determined in the final CSAPR that Texas would be required to reduce SO2 emissions, comply with the annual NOx emission limits, and be in compliance beginning in 2012.  Since the final CSAPR was published on Aug. 8, 2011, SPS has analyzed compliance scenarios and concluded that, unless a new CSAPR allowance market develops quickly, SPS would have to redispatch its system to run its natural gas plants as base load units.  Additionally, SPS would have to substantially reduce coal plant operations in order to comply with the CSAPR using the emission allowances allocated to SPS by the EPA, which requires, for example, a 46 percent reduction in SO2 emissions in 2012.  SPS has estimated that such a substantial change in operations could cost up to $250 million in 2012, mostly due to increased fuel costs, as well as increase risk to reliability on its system.  SPS also expects that in order to comply with the CSAPR, its entire system will have to reduce NOx emissions by 33 percent in 2012.   SPS expects it will be able to recover these costs through regulatory mechanisms and it does not expect a material impact on its results of operations.

On Oct. 6, 2011, the EPA proposed two relevant changes to revise the CSAPR.  SPS’ initial analysis indicates that this proposed rule, if finalized, would not appreciably change the CSAPR’s adverse impact on SPS and its customers, because SPS is constrained by both NOx and SO2 emission reduction obligations under the rule.  SPS remains concerned that the allowance market will not develop to the extent necessary to defray the cost and reliability risks associated with the CSAPR.  SPS has preliminarily concluded that the proposal may reduce the cost of compliance by a modest amount if finalized, but it would not significantly alleviate the risks associated with the 2012 compliance date.

SPS filed two petitions with the EPA for reconsideration and stay of the CSAPR as it applies to the requirement for annual emission reductions in Texas.  In addition, SPS filed a petition for review of the CSAPR with the U.S. Court of Appeals for the D.C. Circuit (D.C. Circuit) that challenges the inclusion of Texas in the CSAPR’s annual reduction programs and the 2012 compliance date.  Along with the petition for review, SPS also filed a motion for stay of the CSAPR with the D.C. Circuit.  SPS expects that the court will rule on the motion for stay by the end of 2011.  Success in these legal actions could reduce SPS’ costs to comply with the CSAPR substantially.  SPS expects it will be able to recover legal costs through regulatory mechanisms and it does not expect a material impact on its results of operations.

SPS continues to evaluate its compliance strategy.  SPS believes the cost of any required capital investment, allowance purchases or costs associated with redispatch will be recoverable from customers.

Clean Air Interstate Rule (CAIR) — In 2005, the EPA issued the CAIR to further regulate SO2 and NOx emissions.  In 2008, the D.C. Circuit vacated and remanded the CAIR, but subsequently allowed the CAIR to continue into effect pending the EPA’s adoption of a new rule that addressed the deficiencies found by the court.  In 2011, the EPA finalized the CSAPR to replace CAIR beginning in 2012.  The CAIR applies to Texas.

Under the CAIR’s cap and trade structure, companies can comply through capital investments in emission controls or purchase of emission allowances from other utilities making reductions on their systems.  The remaining scheduled capital investments for NOx controls in the SPS region are estimated at $16.4 million.  At Sept. 30, 2011, the estimated annual CAIR NOx allowance cost for SPS was $0.1 million.  At the end of 2011, the CAIR will end and compliance efforts will transition to the CSAPR beginning in 2012.  No allowance trading is allowed between the CAIR and CSAPR programs.

Electric Generating Unit (EGU) Maximum Achievable Control Technology (MACT) Rule — In 2005, the EPA issued the Clean Air Mercury Rule (CAMR), which regulated mercury emissions from power plants.  In February 2008, the U.S. Court of Appeals for the District of Columbia vacated the CAMR, which impacted federal CAMR requirements, but not necessarily state-only mercury legislation and rules.

In March 2011, the EPA issued the proposed EGU MACT designed to address emissions of mercury and other hazardous air pollutants for coal-fired utility units greater than 25 MW.  The EPA has indicated that it intends to issue the final rule in December 2011.  SPS anticipates that the EPA will require affected facilities to demonstrate compliance within three to four years.  SPS believes these costs would be recoverable through regulatory mechanisms, and it does not expect a material impact on its results of operations.

Regional Haze Rules — In 2005, the EPA finalized amendments to its regional haze rules regarding provisions that require the installation and operation of emission controls, known as best available retrofit technology (BART), for industrial facilities emitting air pollutants that reduce visibility in certain national parks and wilderness areas throughout the U.S.  Some of SPS’ generating facilities will be subject to BART requirements.  Some of these facilities are located in regions where the CAIR is effective.  Individual states are required to identify the facilities located in their states that will have to reduce SO2, NOx and particulate matter emissions under BART and then set emissions limits for those facilities.  The Texas Commission on Environmental Quality has determined that facilities may use the CAIR as a substitute for BART for NOx and SO2.

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Proposed Coal Ash Regulation — SPS’ operations generate hazardous wastes that are subject to the Federal Resource Recovery and Conservation Act and comparable state laws that impose detailed requirements for handling, storage, treatment and disposal of hazardous waste.  In June 2010, the EPA published a proposed rule seeking comment on whether to regulate coal combustion byproducts (often referred to as coal ash) as hazardous or nonhazardous waste.  Coal ash is currently exempt from hazardous waste regulation.  If the EPA ultimately issues a final rule under which coal ash is regulated as hazardous waste, SPS’ costs associated with the management and disposal of coal ash would significantly increase, and the beneficial reuse of coal ash would be negatively impacted.  The EPA has not announced a planned date for a final rule.  The timing, scope and potential cost of any final rule that might be implemented are not determinable at this time.

Cunningham Compliance Order — In February 2010, SPS received a draft compliance order from the New Mexico Environment Department (NMED) for Cunningham Station.  In the draft order, the NMED alleges that Cunningham exceeded its permit limits for NOx and failed to report these exceedances as required by its permit.   Prior to the formal administrative hearings, SPS negotiated a penalty of $0.8 million.  The final agreement is currently being completed by both parties.

Legal Contingencies

Lawsuits and claims arise in the normal course of business. Management, after consultation with legal counsel, has recorded an estimate of the probable cost of settlement or other disposition. The ultimate outcome of these matters cannot presently be determined. Accordingly, the ultimate resolution of these matters could have a material effect on SPS’ financial position and results of operations.

Environmental Litigation

State of Connecticut vs. Xcel Energy Inc. et al. — In 2004, the attorneys general of eight states and New York City, as well as several environmental groups, filed lawsuits in U.S. District Court for the Southern District of New York against the following utilities, including Xcel Energy Inc., the parent company of SPS, to force reductions in carbon dioxide (CO2) emissions:  American Electric Power Co., Southern Co., Cinergy Corp. (merged into Duke Energy Corporation) and Tennessee Valley Authority.  The lawsuits allege that CO2 emitted by each company is a public nuisance.  The lawsuits do not demand monetary damages.  Instead, the lawsuits ask the court to order each utility to cap and reduce its CO2 emissions.  In September 2005, the court granted plaintiffs’ motion to dismiss on constitutional grounds.  In August 2010, this decision was reversed by the Second Circuit and was appealed to the U.S. Supreme Court.  In June 2011, the Supreme Court issued a ruling reversing the Second Circuit’s decision, thereby dismissing plaintiffs’ federal claims and remanding the case for further proceedings regarding the state law claims.  In September 2011, plaintiffs submitted a letter to the Second Circuit seeking to voluntarily dismiss the complaint.

Native Village of Kivalina vs. Xcel Energy Inc. et al. — In 2008, the City and Native Village of Kivalina, Alaska, filed a lawsuit in U.S. District Court for the Northern District of California against Xcel Energy Inc., the parent company of SPS, and 23 other utility, oil, gas and coal companies.  Plaintiffs claim that defendants’ emission of CO2 and other GHGs contribute to global warming, which is harming their village.  Xcel Energy Inc. and SPS believe the claims asserted in this lawsuit are without merit and joined with other utility defendants in filing a motion to dismiss in June 2008.  In October 2009, the U.S. District Court dismissed the lawsuit on constitutional grounds.  In November 2009, plaintiffs filed a notice of appeal to the U.S. Court of Appeals for the Ninth Circuit.  Oral arguments are set for Nov. 28, 2011.  It is unknown when the Ninth Circuit will render a final opinion.  The amount of damages claimed by plaintiffs is unknown, but likely includes the cost of relocating the village of Kivalina.  Plaintiffs’ alleged relocation is estimated to cost between $95 million to $400 million.  No accrual has been recorded for this matter.

Comer vs. Xcel Energy Inc. et al. — On May 27, 2011, less than a year after their initial lawsuit was dismissed, plaintiffs in this purported class action lawsuit filed a second lawsuit against more than 85 utility, oil, chemical and coal companies in U.S. District Court in Mississippi.  The complaint alleges defendants’ CO2 emissions intensified the strength of Hurricane Katrina and increased the damage plaintiffs purportedly sustained to their property.  Plaintiffs base their claims on public and private nuisance, trespass and negligence.  Among the defendants named in the complaint are Xcel Energy Inc., SPS, PSCo, NSP-Wisconsin and NSP-Minnesota.  The amount of damages claimed by plaintiffs is unknown.  It is believed that this lawsuit is without merit.  No accrual has been recorded for this matter.

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Employment, Tort and Commercial Litigation

Exelon Wind (formerly John Deere Wind) Complaint—Three lawsuits have been filed by John Deere Wind Energy subsidiaries (JD Wind) arising out of a dispute concerning SPS’ payments for energy produced from JD Wind projects.  The first lawsuit was filed in June 2009 in Texas State District Court against the Public Utility Commission of Texas (PUCT).  In this lawsuit, JD Wind filed a petition seeking review of a May 2009 PUCT order denying JD Wind’s request for relief against SPS.  The PUCT has denied all allegations contained in this petition.  On April 21, 2011, JD Wind filed a non-suit of this case dropping the state appeal of the PUCT order so it could pursue its U.S. District Court action.

A second lawsuit was filed in December 2009 by JD Wind against the PUCT in U.S. District Court for the Western District of Texas.  This lawsuit was filed shortly after a declaratory order issued by the Federal Energy Regulatory Commission (FERC) stated that the PUCT’s May 2009 order (approving SPS’ payments to JD Wind) is not consistent with the FERC’s regulations.  In this lawsuit, JD Wind seeks declaratory and injunctive relief against the PUCT.  The U.S. District Court issued an order preventing this lawsuit from proceeding pending the outcome of the state court proceeding against the PUCT.  As a result of the non-suit of the state court proceeding, this case will now move forward with a trial date set for October 2012.

In January 2010, a third lawsuit was filed by JD Wind against SPS in Texas State District Court related to payments made by SPS for energy produced from the JD Wind projects.  This lawsuit seeks unspecified damages against SPS.  It is uncertain when this lawsuit will conclude.  No accrual has been recorded for this lawsuit nor is it expected that this proceeding will have a material effect upon SPS’ results of operations, cash flows or financial position.

On Dec. 9, 2010, all the JD Wind entities were purchased by Exelon Generation Company, LLC and the names of each of the JD Wind entities has been changed to Exelon Wind.  The captions in the U.S. District Court case and the Texas State District Court case have been changed to reflect the change in the names and ownership.

7. Borrowings and Other Financing Instruments

Commercial Paper — SPS meets its short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under its credit facility.  The following table presents commercial paper outstanding for SPS:

(Millions of Dollars)	Three Months Ended Sept. 30, 2011			Twelve Months Ended Dec. 31, 2010
Borrowing limit	$	300		$	248
Amount outstanding at period end		-			49
Average amount outstanding		64			8
Maximum amount outstanding		161			65
Weighted average interest rate, computed on a daily basis		0.36	%		0.37	%
Weighted average interest rate at period end		N/A			0.37

Credit Facilities — 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 the credit agreement.

During March 2011, SPS executed a new four-year credit agreement.  The total size of the credit facility is $300 million and terminates in March 2015. SPS has the right to request an extension of the revolving termination date for two additional one-year periods, subject to majority bank group approval.

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.  Other features of SPS’ credit facility include:

· The credit facility may be increased by up to $50 million.

· The credit facility has a financial covenant requiring that SPS’ debt-to-total capitalization ratio be less than or equal to 65 percent.  SPS was in compliance as its debt-to-total capitalization ratio was 48 percent at Sept. 30, 2011.  If SPS does not comply with the covenant, an event of default may be declared, and if not remedied, any outstanding amounts due under the facility can be declared due by the lender.

· The credit facility has a cross-default provision that provides SPS will be in default on its borrowings under the facility if SPS or any of its future significant subsidiaries whose total assets exceed 15 percent of SPS’ total assets, default on certain indebtedness in an aggregate principal amount exceeding $75 million.

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· The interest rates under the line of credit are based on the Eurodollar rate or an alternate base rate, plus a borrowing margin of 0 to 200 basis points per year based on the applicable credit ratings.

· The commitment fees, also based on applicable long-term credit ratings, are calculated on the unused portion of the line of credit at a range of 10 to 35 basis points per year.

At Sept. 30, 2011, SPS had the following committed credit facility available (in millions of dollars):

Credit Facility		Drawn		Available
$	300.0	$	-	$	300.0

All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity under the credit facility.  SPS had no direct advances on the credit facility outstanding at Sept. 30, 2011 and Dec. 31, 2010.

Letters of Credit — SPS uses letters of credit, generally with terms of one-year, to provide financial guarantees for certain operating obligations.  At Sept. 30, 2011 and Dec. 31, 2010 there were no letters of credit outstanding.

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 utility money pool arrangement does not allow the utility subsidiaries to make investments in Xcel Energy Inc.

The following table presents the money pool borrowings for SPS:

(Millions of Dollars)	Three Months Ended Sept. 30, 2011			Twelve Months Ended Dec. 31, 2010
Borrowing limit	$	100		$	100
Amount outstanding at period end		-			-
Average amount outstanding		2			16
Maximum amount outstanding		20			77
Weighted average interest rate, computed on a daily basis		0.35	%		0.37	%
Weighted average interest rate at period end		N/A			N/A

Long-Term Borrowings

In August 2011, SPS issued $200 million of 4.50 percent first mortgage bonds due Aug. 15, 2041.  SPS used a portion of the net proceeds from the sale of the first mortgage bonds to repay short-term debt borrowings incurred to fund daily operational needs and to redeem $57.3 million of the outstanding 5.75 percent Pollution Control Revenue Refunding Bonds due Sept. 1, 2016.  The balance of the net proceeds was used for general corporate purposes.

8. Fair Value of Financial Assets and Liabilities

Fair Value Measurements

SPS had no assets or liabilities measured at fair value on a recurring basis as of Sept. 30, 2011 and Dec. 31, 2010.

Derivative Instruments

SPS may enter into derivative instruments, including forward contracts, futures, swaps and options, to reduce risk in connection with changes in interest rates and electric utility commodity prices.

Interest Rate Derivatives — SPS may enter into various instruments that effectively fix the interest payments on certain floating rate debt obligations or effectively fix the yield or price on a specified benchmark interest rate for an anticipated debt issuance for a specific period.  These derivative instruments are generally designated as cash flow hedges for accounting purposes.

At Sept. 30, 2011, accumulated other comprehensive losses related to interest rate derivatives included $0.2 million of net losses expected to be reclassified into earnings during the next 12 months as the related hedged interest rate transactions impact earnings.

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Accumulated other comprehensive losses related to interest rate derivatives reclassified into earnings during each of the three months ended Sept. 30, 2011 and Sept. 30, 2010 were $0.1 million.  Accumulated other comprehensive losses related to interest rate derivatives reclassified into earnings during each of the nine months ended Sept. 30, 2011 and Sept. 30, 2010 were $0.2 million.

Short-Term Wholesale and Commodity Trading Risk — SPS conducts an immaterial amount of short-term wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy and energy-related products.  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 the policy.

Commodity Derivatives — SPS may enter into derivative instruments to manage variability of future cash flows from changes in commodity prices in its electric utility operations.  This could include the purchase or sale of energy or energy-related products.  At Sept. 30, 2011 and Dec. 31, 2010, SPS held no commodity derivatives.  Changes in the fair value of non-trading commodity derivative instruments are recorded in other comprehensive income or deferred as a regulatory asset or liability.  The classification as a regulatory asset or liability is based on the commission approved regulatory recovery mechanisms.

At Sept. 30, 2011 and Dec. 31, 2010, derivative instruments presented on SPS’ balance sheets consists of amounts related to long-term purchased power agreements.  In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, SPS began recording several long-term purchased power agreements 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.

Financial Impact of Qualifying Cash Flow Hedges — The impact of qualifying interest rate cash flow hedges on SPS’ accumulated other comprehensive income, included as a component of common stockholder’s equity, is detailed in the following table:

	Three Months Ended Sept. 30,
(Thousands of Dollars)	2011				2010
Accumulated other comprehensive loss related to cash flow hedges at July 1		$	(1,589	)		$	(1,762	)
After-tax net realized losses on derivative transactions reclassified into earnings			42				44
Accumulated other comprehensive loss related to cash flow hedges at Sept. 30		$	(1,547	)		$	(1,718	)

	Nine Months Ended Sept. 30,
(Thousands of Dollars)	2011				2010
Accumulated other comprehensive loss related to cash flow hedges at Jan. 1		$	(1,675	)		$	(1,847	)
After-tax net realized losses on derivative transactions reclassified into earnings			128				129
Accumulated other comprehensive loss related to cash flow hedges at Sept. 30		$	(1,547	)		$	(1,718	)

Fair Value of Long-Term Debt

The historical cost and fair value of SPS’ long-term debt are as follows:

	Sept. 30, 2011				Dec. 31, 2010
	Historical				Historical
(Thousands of Dollars)	Cost		Fair Value		Cost		Fair Value
Long-term debt, including current portion	$	993,208	$	1,153,366	$	897,767	$	989,789

The fair value of SPS’ long-term debt is estimated based on the quoted market prices for the same or similar issues or the current rates for debt of the same remaining maturities and credit quality.  The fair value estimates presented are based on information available to management as of Sept. 30, 2011 and Dec. 31, 2010.  These fair value estimates have not been comprehensively revalued for purposes of these financial statements since that date and current estimates of fair value may differ significantly.

As of Sept. 30, 2011 and Dec. 31, 2010, the historical cost of cash and cash equivalents, accounts receivable, accounts payable and short-term debt are representative of fair value because of the short-term nature of these instruments.

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9. Other Income (Expense), Net

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

	Three Months Ended Sept. 30,					Nine Months Ended Sept. 30,
(Thousands of Dollars)	2011		2010			2011		2010
Interest income	$	140	$	71		$	374	$	168
Other nonoperating income		4		-			7		11
Insurance policy income (expense)		142		(153	)		51		(148	)
Other income (expense), net	$	286	$	(82	)	$	432	$	31

10. Segment Information

SPS has only one reportable segment.  SPS is a wholly owned subsidiary of Xcel Energy Inc. and operates in the regulated electric utility industry providing wholesale and retail electric service in the states of Texas and New Mexico.  Revenues from external customers were $522.9 million and $467.4 million for the three months ended Sept. 30, 2011 and 2010, respectively and $1,337.4 million and $1,247.4 million for the nine months ended Sept. 30, 2011 and 2010, respectively.

Operating results from the regulated electric utility segment serve as the primary basis for the chief operating decision maker to evaluate the performance of SPS.

11. Comprehensive Income

The components of total comprehensive income are shown below:

	Three Months Ended Sept. 30,				Nine Months Ended Sept. 30,
(Thousands of Dollars)	2011		2010		2011		2010
Net income	$	48,581	$	39,189	$	83,491	$	71,284
Other comprehensive income:
After-tax net realized losses on derivative transactions reclassified into earnings		42		44		128		129
Comprehensive income	$	48,623	$	39,233	$	83,619	$	71,413

12. Benefit Plans and Other Postretirement Benefits

Pension and other postretirement benefit disclosures below generally represent Xcel Energy information unless specifically identified as being attributable to SPS.

SPS calculates base pension expense in accordance with accounting guidance for retirement benefits.  In 2011, the Texas retail electric jurisdiction began to allow the deferral of allocated pension costs to the extent that those costs exceed test year pension expenses included in rates, within prescribed limits.  Differences between regulatory-based pension expense for the Texas retail electric jurisdiction and expense as calculated under applicable accounting guidance are deferred as a regulatory asset or liability.

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Components of Net Periodic Benefit Cost

	Three Months Ended Sept. 30,
	2011			2010			2011			2010
							Postretirement Health
(Thousands of Dollars)	Pension Benefits						Care Benefits
Xcel Energy
Service cost	$	19,330		$	18,286		$	1,206		$	1,002
Interest cost		40,353			41,253			10,522			10,695
Expected return on plan assets		(55,400	)		(58,080	)		(7,991	)		(7,132	)
Amortization of transition obligation		-			-			3,611			3,611
Amortization of prior service cost (credit)		5,633			5,165			(1,233	)		(1,233	)
Amortization of net loss		19,627			12,078			3,324			2,910
Net periodic benefit cost		29,543			18,702			9,439			9,853
Costs not recognized and additional cost recognized due to the effects of regulation		(9,299	)		(6,630	)		972			972
Net benefit cost recognized for financial reporting	$	20,244		$	12,072		$	10,411		$	10,825
SPS
Net periodic benefit cost	$	2,990		$	1,448		$	820		$	900
Costs not recognized due to the effects of regulation		(575	)		-			-			-
Net benefit cost recognized for financial reporting	$	2,415		$	1,448		$	820		$	900

	Nine Months Ended Sept. 30,
	2011			2010			2011			2010
							Postretirement Health
(Thousands of Dollars)	Pension Benefits						Care Benefits
Xcel Energy
Service cost	$	57,990		$	54,860		$	3,618		$	3,005
Interest cost		121,059			123,758			31,565			32,085
Expected return on plan assets		(166,200	)		(174,239	)		(23,972	)		(21,397	)
Amortization of transition obligation		-			-			10,833			10,833
Amortization of prior service cost (credit)		16,899			15,493			(3,699	)		(3,699	)
Amortization of net loss		58,883			36,236			9,971			8,732
Net periodic benefit cost		88,631			56,108			28,316			29,559
Costs not recognized and additional cost recognized due to the effects of regulation		(27,899	)		(20,270	)		2,918			2,918
Net benefit cost recognized for financial reporting	$	60,732		$	35,838		$	31,234		$	32,477
SPS
Net periodic benefit cost	$	8,971		$	4,345		$	2,461		$	2,701
Costs not recognized due to the effects of regulation		(1,725	)		-			-			-
Net benefit cost recognized for financial reporting	$	7,246		$	4,345		$	2,461		$	2,701

Voluntary contributions of $134 million were made to three of Xcel Energy’s pension plans in January 2011, including $4.2 million related to SPS.  Based on updated valuation results received in March 2011 for the New Century Energies, Inc. (NCE) Non-Bargaining Pension Plan, Xcel Energy made a required contribution of $3.3 million to the NCE Non-Bargaining Pension Plan in July 2011.  Xcel Energy does not expect additional pension contributions during 2011.

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

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

Financial Review

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

Forward-Looking Statements

Except for the historical statements contained in this report, the matters discussed in the following discussion and analysis are forward-looking statements that are subject to certain risks, uncertainties, and assumptions.  Such forward-looking statements are intended to be identified in this document by the words “anticipate,” “believe,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should” and similar expressions. Actual results may vary materially. Forward-looking statements speak only as of the date they are made, and we do not undertake any obligation to update them to reflect changes that occur after that date. Factors that could cause actual results to differ materially include, but are not limited to: general economic conditions, including inflation rates, monetary fluctuations and their impact on capital expenditures and the ability of SPS to obtain financing on favorable terms; business conditions in the energy industry; including the risk of a 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; 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; state, federal and foreign legislative and regulatory initiatives that affect cost and investment recovery, have an impact on rates or have an impact on asset operation or ownership or impose environmental compliance conditions; structures that affect the speed and degree to which competition enters the electric market; costs and other effects of legal and administrative proceedings, settlements, investigations and claims; financial or regulatory accounting policies imposed by regulatory bodies; availability or cost of capital; employee work force factors; the items described under Factors Affecting Results of Operations; and the other risk factors listed from time to time by SPS in reports filed with the SEC, including “Risk Factors” in Item 1A of SPS’ Form 10-K for the year ended Dec. 31, 2010, and Item 1A and Exhibit 99.01 to this Quarterly Report on Form 10-Q for the quarter ended Sept. 30, 2011.

Results of Operations

SPS’ net income was approximately $83.5 million for the nine months ended Sept. 30, 2011, compared with net income of approximately $71.3 million for the same period in 2010.  Higher electric revenues, primarily due to the Texas retail rate increases in February 2011 as well as warmer weather were partially offset by higher O&M expenses, depreciation expense and property taxes.

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:

		Nine Months Ended Sept. 30,
(Millions of Dollars)		2011			2010
Electric revenues	$	1,337		$	1,247
Electric fuel and purchased power		(851	)		(788	)
Electric margin	$	486		$	459

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The following tables summarize the components of the changes in electric revenues and electric margin:

Electric Revenues

(Millions of Dollars)	2011 vs. 2010
Fuel and purchased power cost recovery	$	39
Transmission revenue		21
Firm wholesale (a)		18
Retail rate increase (Texas)		11
Trading		8
Estimated impact of weather		8
Demand side management (DSM) revenue (offset by expenses)		3
DSM incentive		2
SPS fuel cost allocation regulatory accruals (b)		(11	)
Retail sales decrease (excluding weather impact) (a)		(8	)
Other, net		(1	)
Total increase in electric revenues	$	90

(a) Firm wholesale and retail sales decrease have not been adjusted for impacts of the sale of SPS electric distribution assets to the city of Lubbock, Texas in October 2010.  As a result of the sale of distribution assets, approximately $10.2 million in sales to the city of Lubbock which were previously included in retail sales are now included in firm wholesale.

(b) During the second quarter of 2010, SPS resolved certain fuel cost allocation issues allowing for the release of previously established reserves of approximately $11 million.

Electric Margin
(Millions of Dollars)	2011 vs. 2010
Firm wholesale (a)	$	17
Retail rate increase (Texas)		11
Transmission revenue, net of costs		9
Estimated impact of weather		8
DSM revenue (offset by expenses)		3
DSM incentive		2
SPS fuel cost allocation regulatory accruals (b)		(11	)
Retail sales decrease (excluding weather impact) (a)		(8	)
Trading		(1	)
Other, net		(3	)
Total increase in electric margin	$	27

(a) Firm wholesale and retail sales decrease have not been adjusted for impacts of the sale of SPS electric distribution assets to the city of Lubbock, Texas in October 2010.  As a result of the sale of distribution assets, approximately $10.2 million in sales to the city of Lubbock which were previously included in retail sales are now included in firm wholesale.

(b) During the second quarter of 2010, SPS resolved certain fuel cost allocation issues allowing for the release of previously established reserves of approximately $11 million.

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Non-Fuel Operating Expense and Other Items

O&M Expenses — O&M expenses for the nine months ended Sept. 30, 2011 increased $6.3 million, or 3.5 percent, compared to the same period in 2010.  The following summarizes the components of the changes for O&M expenses:

(Millions of Dollars)	2011 vs. 2010
Higher labor and contract labor costs	$	4
Higher plant generation costs		3
Higher employee benefit expense		1
Other, net		(2	)
Total increase in O&M expenses	$	6

DSM Program Expenses — DSM program expenses increased by approximately $4.1 million for the nine months ended Sept. 30, 2011 compared with the same period in 2010. The higher expense is primarily attributable to an increase in the rider rates used to recover the program expenses.  DSM program expenses are generally recovered in our major jurisdictions concurrently through riders and base rates.  Overall the programs are designed to encourage the operating companies and their retail customers to conserve energy or change energy usage patterns in order to reduce peak demand on the electric system.  This, in turn, reduces the need for additional plant capacity, reduces emissions, serves to achieve other environmental goals as well as reduces energy costs to participating customers.

Depreciation and Amortization — Depreciation and amortization expenses increased by approximately $2.2 million, or 2.8 percent for the nine months ended Sept. 30, 2011 compared with the same period in 2010.  The year to date increase in depreciation expense is primarily due to normal system expansion.

Taxes (Other Than Income Taxes) — Taxes (other than income taxes) increased by approximately $0.9 million, or 3.1 percent for the nine months ended Sept. 30, 2011, compared with the same period in 2010.  The increase is primarily due to an increase in property taxes in Texas.

Allowance for Funds Used During Construction, Debt and Equity (AFUDC) — AFUDC increased by approximately $2.6 million, for the nine months ended Sept. 30, 2011 compared with the same period in 2010.  This increase was primarily due to higher average construction work in progress due to major construction projects, including Jones Unit 3 and Unit 4, as well as transmission projects.

Income Taxes — Income tax expense increased by $4.6 million for the nine months ended Sept. 30, 2011, compared with the same period in 2010.  The increase in income tax expense was primarily due to an increase in pretax income in 2011, partially offset by a write-off of tax benefits previously recorded for Medicare Part D subsidies in 2010.  The effective tax rate was 38.2 percent for the first nine months of 2011, compared with 39.8 percent for the same period in 2010. The higher effective tax rate for the first nine months of 2010 was primarily due to the write-off of tax benefit for Medicare Part D subsidies in 2010. Without this write-off, the effective tax rate for the first nine months of 2010 would have been 38.2 percent.

Factors Affecting Results of Operations

Public Utility Regulation

New Mexico Energy Efficiency Disincentive Rulemaking— During the 2008 New Mexico legislative session, increased energy efficiency goals and removal of disincentives were adopted.  In 2010, the NMPRC adopted an amended rule incorporating the legislative changes.  The rule had an interim mechanism that provides for recovery of disincentives and required utilities to file permanent rate design or other means of removing disincentives.

In July 2010, SPS filed its application to remove disincentives and requested direct lost margin recovery.  A final approval order was received in December 2010 totaling $3.3 million for 2010 and 2011.

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Subsequently, SPS filed a plan to implement the rule by recovering both an incentive and disincentive amount.  SPS and NMPRC Staff and several environmental groups reached a settlement that would allow for a combined recovery of disincentives and incentives of $2.0 million per year for the years 2012, 2013 and 2014 unless rates from a future SPS rate case (other than the currently pending rate case) become effective prior to the end of the 2014 calendar year, in which event, the stipulated recovery would apply only to those periods prior to the effective date from that rate case.  The New Mexico Attorney General and the New Mexico Industrial Energy Consumers oppose the settlement.  A hearing in this case that focuses on the appropriate long-term mechanism was held in April 2011 and the hearing examiner issued a recommended decision to affirm the settlement in September 2011.

New Mexico GHG Regulations — In 2010, the New Mexico Environmental Improvement Board (EIB) adopted two regulations to limit GHG emissions, including CO2 emissions from power plants and other industrial sources. SPS, other utilities and industry groups have filed separate appeals with the New Mexico Court of Appeals challenging the validity of these two GHG regulations.  The appellate cases have been stayed pending further proceedings before the EIB.  In July 2011, SPS and other parties filed a petition for repeal of each state GHG rule, and the EIB set both petitions for hearing by the end of 2011.  The rules are scheduled to become applicable to SPS beginning in 2013.

Summary of Recent Federal Regulatory Developments

The FERC has jurisdiction over rates for electric transmission service in interstate commerce and electricity sold at wholesale, accounting practices and certain other activities of SPS, including enforcement of North American Electric Reliability Corporation (NERC) 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, 2010.  In addition to the matters discussed below, see Note 5 to the financial statements for a discussion of other regulatory matters.

NERC Electric Reliability Standards Compliance

Compliance Audits

In November 2010, SPS filed a self-report with Southwest Power Pool, Inc. regarding potential violations of certain NERC critical infrastructure protection standards (CIPS).  Additional self-reports of potential violations of CIPS standards were filed in January 2011.  Based on the issues identified with CIPS compliance, SPS submitted a mitigation plan that provides for a comprehensive review of its CIPS compliance programs.  Whether and to what extent penalties may be assessed against SPS for the issues identified and self-reported to date is unclear.

FERC Tie Line Investigation — In October 2007, the FERC Office of Enforcement and the U.S. Department of the Interior (DOI) commenced a non-public investigation of the transmission service arrangements across the Lamar Tie Line, a transmission facility that connects PSCo and SPS.  In July 2008, the DOI issued a preliminary report alleging Xcel Energy violated certain FERC policies, rules and approved tariffs, that could result in material penalties under the FERC penalty guidelines.  The report does not constitute a finding by the FERC, which may accept, modify or reject any or all of the preliminary conclusions set forth in the report.  Xcel Energy disagreed with the preliminary report and demonstrated compliance with applicable standards.  In December 2010, the DOI initiated settlement discussions with Xcel Energy regarding possible resolution of the non-public investigation and settlement discussions are continuing.  The final outcome of the DOI investigation and to what extent the FERC may seek to impose penalties for alleged violations is unknown at this time.  The potential violations are not expected to have a material impact on SPS’ financial condition, results of operations or cash flows.

FERC Order 1000, Transmission Planning and Cost Allocation (Order 1000) —In July 2011, the FERC issued Order 1000 adopting new requirements for transmission planning, cost allocation, and development.  The impacts of Order 1000 on transmission planning and cost allocation for SPS are not expected to be significant as they already participate in regional planning and cost allocation processes.  The impacts of the new requirements related to future transmission development and ownership under  Order 1000 are uncertain at this time.  Compliance filings to address these new requirements are due in October 2012 and are effective prospectively.  In August 2011, motions for rehearing were filed by and are pending action by the FERC.

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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 Sept. 30, 2011, based on an evaluation carried out under the supervision and with the participation of SPS’ management, including the CEO and CFO, of the effectiveness of its disclosure controls and the procedures, the CEO and CFO have concluded that SPS’ disclosure controls and procedures were effective.

Internal Control Over Financial Reporting

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

Part II — OTHER INFORMATION

Item 1 — LEGAL PROCEEDINGS

In the normal course of business, various lawsuits and claims have arisen against SPS. After consultation with legal counsel, SPS has recorded an estimate of the probable cost of settlement or other disposition for such matters.

Additional Information

See Notes 5 and 6 of the financial statements for further discussion of legal proceedings, including Rate Matters and Commitments and Contingent Liabilities, which are hereby incorporated by reference. Reference also is made to Item 3 and Notes 11 and 12 of SPS’ financial statements in its Annual Report on Form 10-K for the year ended Dec. 31, 2010 for a description of certain legal proceedings presently pending.

Item 1A — RISK FACTORS

Except to the extent updated or described below, 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, 2010, which is incorporated herein by reference.

Public Policy Risks

We may be subject to legislative and regulatory responses to climate change and emissions, with which compliance could be difficult and costly.

Increased public awareness and concern regarding climate change may result in more regional and/or federal requirements to reduce or mitigate the effects of GHGs. Numerous states have announced or adopted programs to stabilize and reduce GHGs, and federal legislation has been introduced in both houses of Congress.  Internationally, other nations have already agreed to regulate emissions of GHGs pursuant to the United Nations Framework Convention on Climate Change, also known as the “Kyoto Protocol,” by 2012.  In addition, in 2009, the U.S. submitted a non-binding GHG emission reduction target of 17 percent compared to 2005 levels pursuant to the Copenhagen Accord.  Such legislative and regulatory responses related to climate change and new interpretations of existing laws through climate change litigation create financial risk as our electric generating facilities are likely to be subject to regulation under climate change laws introduced at either the state or federal level within the next few years.

The EPA has taken steps to regulate GHGs under the CAA.  In December 2009, the EPA issued a finding that GHG emissions endanger public health and welfare, and that motor vehicle emissions contribute to the GHGs in the atmosphere. This endangerment finding created a mandatory duty for the EPA to regulate GHGs from light duty motor vehicles. In January 2011, new EPA permitting requirements became effective for GHG emissions of new and modified large stationary sources, which are applicable to construction of new power plants or power plant modifications that increase emissions above a certain threshold. The EPA has also announced that it will propose GHG regulations applicable to emissions from existing power plants, although the EPA announced in late September that this proposed rule will be delayed.

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We are also currently a party to climate change lawsuits and may be subject to additional climate change lawsuits, including lawsuits similar to those described in Note 6 to the financial statements.  An adverse outcome in any of these cases could require substantial capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties or damages. Defense costs associated with such litigation can also be significant. Such payments or expenditures could affect results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates.

Many of the federal and state climate change legislative proposals use a cap and trade policy structure, in which GHG emissions from a broad cross-section of the economy would be subject to an overall cap.  Under the proposals, the cap becomes more stringent with the passage of time. The proposals establish mechanisms for GHG sources, such as power plants, to obtain “allowances” or permits to emit GHGs during the course of a year. The sources may use the allowances to cover their own emissions or sell them to other sources that do not hold enough emission allowances for their own operations. Proponents of the cap and trade policy believe it will result in the most cost effective, flexible emission reductions. There are many uncertainties, however, regarding when and in what form climate change legislation or regulation will be enacted.  The impact of legislation and regulations, including a cap and trade structure, on us and our customers will depend on a number of factors, including whether GHG sources in multiple sectors of the economy are regulated, the overall GHG emissions cap level, the degree to which GHG offsets are allowed, the allocation of emission allowances to specific sources and the indirect impact of carbon regulation on natural gas and coal prices. While we do not have operations outside of the U.S., any international treaties or accords could have an impact to the extent they lead to future federal or state regulations. Another important factor is our ability to recover the costs incurred to comply with any regulatory requirements that are ultimately imposed. We may not be able to timely recover all costs related to complying with regulatory requirements imposed on us. If our regulators do not allow us to recover all or a part of the cost of capital investment or the O&M costs incurred to comply with the mandates, it could have a material effect on our results of operations.

We are also subject to a significant number of proposed and potential rules that will impact our coal-fired and other generation facilities.  These include, but are not limited to, rules associated with mercury, regional haze, ozone, ash management and cooling water intake systems.  The costs of investment to comply with these rules could be substantial.  We may not be able to timely recover all costs related to complying with regulatory requirements imposed on us.

Item 6 — EXHIBITS

* Indicates incorporation by reference

t Furnished, herewith, not filed.  Pursuant to Rule 406T of Regulation S-T, the Interactive Data Files on Exhibit 101 hereto are deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, are deemed not filed for purposes of Section 18 of the Securities and Exchange Act of 1934, as amended, and otherwise are not subject to liability under those sections.

3.01* Amended and Restated Articles of Incorporation dated Sept. 30, 1997 (Exhibit 3(a)(2) to Form 10-K for the year ended Dec. 31, 1997 (file no. 001-03789) dated March 3, 1998).

3.02* By-laws dated Sept. 29, 1997 (Exhibit 3(b)(2) to Form 10-K for the year ended Dec. 31, 1997 (file no. 001-03789) dated March 3, 1998).

4.01* Indenture dated as of Aug. 1, 2011 between SPS and U.S. Bank National Association (NA), as Trustee. (Exhibit 4.01 to Form 8-K dated Aug. 10, 2011 (file no. 001-03789)).

4.02* Supplemental Indenture dated as of Aug. 3, 2011 between SPS and U.S. Bank NA, as Trustee, creating $200 million principal amount of 4.50 percent First Mortgage Bonds, Series No. 1 due 2041. (Exhibit 4.02 to Form 8-K dated Aug. 10, 2011 (file no. 001-03789)).

31.01 Principal Executive Officer’s and 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 t The following materials from SPS’ Quarterly Report on Form 10-Q for the quarter ended Sept. 30, 2011 are formatted in XBRL (eXtensible Business Reporting Language):  (i) the Statements of Income, (ii) the Statements of Cash Flow, (iii) the Balance Sheets, (iv) Notes to Condensed Financial Statements, and (v) 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
Oct. 31, 2011
	By:	/s/ JEFFREY S. SAVAGE
		Jeffrey S. Savage
		Vice President and Controller
		/s/ TERESA S. MADDEN
		Teresa S. Madden
		Senior Vice President and Chief Financial Officer

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