UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549

FORM 10-Q

(Mark One)

x	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2009
or
o	TRANSITION REPORTS 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 requirement for the past 90 days.   xYes  oNo

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).   oYes oNo

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).   oYes  xNo

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

Class	Outstanding at Aug. 3, 2009
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	18
Item 4.	Controls and Procedures	21
PART II - OTHER INFORMATION
Item 1.	Legal Proceedings	21
Item 1A.	Risk Factors	22
Item 6.	Exhibits	23
SIGNATURES		24
Certifications Pursuant to Section 302
Certifications Pursuant to Section 906
Statement Pursuant to Private Litigation

This Form 10-Q is filed by Southwestern Public Service Company (SPS). SPS is a wholly owned subsidiary of Xcel Energy Inc. (Xcel Energy). Additional information on Xcel Energy is available on various filings with the Securities and Exchange Commission (SEC).

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PART I. FINANCIAL INFORMATION

Item 1. FINANCIAL STATEMENTS

SOUTHWESTERN PUBLIC SERVICE COMPANY

STATEMENTS OF INCOME (UNAUDITED)

(amounts in thousands of dollars)

	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
Operating revenues	$	328,140		$	537,873		$	697,123		$	956,670
Operating expenses
Electric fuel and purchased power	196,010			425,991			443,519			747,683
Other operating and maintenance expenses	53,956			54,605			108,429			106,030
Demand side management program expenses	2,621			4,682			3,973			5,661
Depreciation and amortization	25,279			24,386			50,554			48,373
Taxes (other than income taxes)	9,231			9,780			19,773			20,103
Total operating expenses	287,097			519,444			626,248			927,850
Operating income	41,043			18,429			70,875			28,820
Interest and other (expenses) income, net	(323		)	1,367			42			2,230
Allowance for funds used during construction — equity	975			—			2,090			—
Interest charges and financing costs
Interest charges — includes other financing costs of $657, $590, $1,326 and $1,181, respectively	15,582			13,553			33,682			27,484
Allowance for funds used during construction — debt	(675		)	(604		)	(1,445		)	(1,260		)
Total interest charges and financing costs	14,907			12,949			32,237			26,224
Income before income taxes	26,788			6,847			40,770			4,826
Income taxes	9,980			2,877			14,780			2,121
Net income	$	16,808		$	3,970		$	25,990		$	2,705

See Notes to Financial Statements

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SOUTHWESTERN PUBLIC SERVICE COMPANY

STATEMENTS OF CASH FLOWS (UNAUDITED)

(amounts in thousands of dollars)

	Six Months Ended June 30,
	2009			2008
Operating activities
Net income	$	25,990		$	2,705
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	52,542			56,733
Deferred income taxes	(19,432		)	13,791
Amortization of investment tax credits	(162		)	(110		)
Allowance for equity funds used during construction	(2,090		)	—
Net realized and unrealized hedging and derivative transactions	(1,509		)	134
Changes in operating assets and liabilities:
Accounts receivable	(6,490		)	(25,927		)
Accrued unbilled revenues	(10,842		)	(39,892		)
Inventories	24,835			(5,084		)
Recoverable electric energy costs	2,018			(60,238		)
Prepayments and other	1,828			3,505
Accounts payable	(25,550		)	80,165
Deferred electric energy costs	92,428			(39		)
Net regulatory assets and liabilities	3,655			(1,056		)
Other current liabilities	(5,567		)	(13,789		)
Change in other noncurrent assets	(5,064		)	(5,398		)
Change in other noncurrent liabilities	(17,291		)	6,797
Net cash provided by operating activities	109,299			12,297
Investing activities
Utility capital/construction expenditures	(96,006		)	(83,843		)
Allowance for equity funds used during construction	2,090			—
Investments in utility money pool arrangement	(567,800		)	—
Receipts from utility money pool arrangement	658,300			—
Other investments	—			2,166
Net cash used in investing activities	(3,416		)	(81,677		)
Financing activities
Repayment of short-term borrowings, net	—			76,000
Borrowings under utility money pool arrangement	—			379,100
Repayments under utility money pool arrangement	—			(354,600		)
Repayment of long-term debt, including reacquisition premiums	(100,027		)	—
Capital contributions from parent	13,044			2,095
Dividends paid to parent	(32,959		)	(31,753		)
Net cash (used in) provided by financing activities	(119,942		)	70,842
Net (decrease) increase in cash and cash equivalents	(14,059		)	1,462
Cash and cash equivalents at beginning of period	130,795			714
Cash and cash equivalents at end of period	$	116,736		$	2,176
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	(33,455	)	$	(25,425	)
Cash paid for income taxes (net of refunds received)	(34,363		)	(10,007		)
Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable	$	3,751		$	2,939

See the Notes to Financial Statements

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SOUTHWESTERN PUBLIC SERVICE COMPANY

BALANCE SHEETS (UNAUDITED)

(amounts in thousands of dollars)

	June 30, 2009			Dec. 31, 2008
Assets
Current assets
Cash and cash equivalents	$	116,736		$	130,795
Investments in utility money pool arrangement	—			90,500
Accounts receivable, net	57,032			63,018
Accounts receivable from affiliates	17,304			4,828
Accrued unbilled revenues	108,705			97,863
Inventories	20,563			47,082
Recoverable electric energy costs	3,523			5,540
Derivative instruments valuation	8,926			8,926
Deferred income taxes	56,665			21,607
Prepayments and other	3,541			5,369
Total current assets	392,995			475,528
Property, plant and equipment, net	2,186,540			2,141,636
Other assets
Regulatory assets	262,774			269,344
Derivative instruments valuation	72,088			76,551
Other	28,780			24,048
Total other assets	363,642			369,943
Total assets	$	2,943,177		$	2,987,107
Liabilities and Equity
Current liabilities
Current portion of long-term debt	$	—		$	100,000
Accounts payable	140,180			166,909
Accounts payable to affiliates	9,255			10,568
Deferred electric energy costs	113,364			20,936
Taxes accrued	14,939			20,271
Dividends payable to parent	16,854			15,585
Accrued interest	12,698			15,136
Derivative instruments valuation	5,125			5,079
Other	21,870			19,800
Total current liabilities	334,285			374,284
Deferred credits and other liabilities
Deferred income taxes	502,180			486,702
Deferred investment tax credits	2,528			2,690
Regulatory liabilities	122,974			126,884
Asset retirement obligations	18,501			17,903
Derivative instruments valuation	55,406			59,255
Pension and employee benefit obligations	41,496			50,500
Other	8,090			16,461
Total deferred credits and other liabilities	751,175			760,395
Commitments and contingent liabilities
Capitalization
Long-term debt	922,285			922,123
Common stock — authorized 200 shares of $1.00 par value, outstanding 100 shares	—			—
Additional paid in capital	689,749			676,705
Retained earnings	250,922			259,159
Accumulated other comprehensive loss	(5,239		)	(5,559		)
Total common stockholder’s equity	935,432			930,305
Total liabilities and equity	$	2,943,177		$	2,987,107

See the 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 June 30, 2009, and Dec. 31, 2008; the results of its operations for the three and six months ended June 30, 2009 and 2008; and its cash flows for the six months ended June 30, 2009 and 2008. All adjustments are of a normal, recurring nature, except as otherwise disclosed.  Management has also evaluated the impact of events occurring after June 30, 2009 up to Aug. 3, 2009, which is the date of issuance of these financial statements.  These statements contain all necessary adjustments and disclosures resulting from that evaluation.  The Dec. 31, 2008 balance sheet information has been derived from the audited 2008 financial statements. 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 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, 2008, filed with the SEC on March 2, 2009.  Due to the seasonality of electric sales of SPS, interim results are not necessarily an appropriate base from which to project annual results.

1.     Summary of Significant Accounting Policies

Except to the extent updated or described below, the significant accounting policies set forth in Note 1 to the financial statements in SPS’ Annual Report on Form 10-K for the year ended Dec. 31, 2008, appropriately represent, in all material respects, the current status of accounting policies and are incorporated herein by reference.

2.     Accounting Pronouncements

Recently Adopted

Business Combinations (Statement of Financial Accounting Standards (SFAS) No. 141 (revised 2007)) — In December 2007, the Financial Accounting Standards Board (FASB) issued SFAS No. 141(R), which establishes principles and requirements for how an acquirer in a business combination recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest; recognizes and measures the goodwill acquired in the business combination or a gain from a bargain purchase; and determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of the business combination. SFAS No. 141(R) is to be applied prospectively to business combinations for which the acquisition date is on or after the beginning of an entity’s fiscal year that begins on or after Dec. 15, 2008. SPS implemented SFAS No. 141(R) on Jan. 1, 2009, and the implementation did not have a material impact on its financial statements.

Noncontrolling Interests in Consolidated Financial Statements, an Amendment of Accounting Research Bulletin (ARB) No. 51 (SFAS No. 160) — In December 2007, the FASB issued SFAS No. 160, which establishes accounting and reporting standards that require the ownership interest in subsidiaries held by parties other than the parent be clearly identified and presented in the consolidated balance sheets within equity, but separate from the parent’s equity; the amount of consolidated net income attributable to the parent and the noncontrolling interest be clearly identified and presented on the face of the consolidated statement of earnings; and changes in a parent’s ownership interest while the parent retains its controlling financial interest in its subsidiary be accounted for consistently as equity transactions. SFAS No. 160 was effective for fiscal years beginning on or after Dec. 15, 2008. SPS implemented SFAS No. 160 on Jan. 1, 2009, and the implementation did not have a material impact on its financial statements.

Disclosures about Derivative Instruments and Hedging Activities, an amendment of FASB Statement No. 133 (SFAS No. 161) — In March 2008, the FASB issued SFAS No. 161, which is intended to enhance disclosures to help users of the financial statements better understand how derivative instruments and hedging activities affect an entity’s financial position, financial performance and cash flows.  SFAS No. 161 amends and expands the disclosure requirements of SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, to require disclosures including objectives and strategies for using derivatives, gains and losses on derivative instruments, and credit-risk-related contingent features in derivative contracts.  SFAS No. 161 was effective for financial statements issued for fiscal years and interim periods beginning after Nov. 15, 2008.  SPS implemented SFAS No. 161 on Jan. 1, 2009, and the implementation did not have a material impact on its financial statements.  For further discussion and SFAS No. 161 required disclosures, see Note 8 to the financial statements.

6

Interim Disclosures about Fair Value of Financial Instruments (FASB Staff Position (FSP) FAS 107-1 and Accounting Principles Board (APB) 28-1) —In April 2009, the FASB issued FSP FAS 107-1 and APB 28-1, which amends SFAS No. 107, Disclosures About Fair Value of Financial Instruments, and APB Opinion No. 28, Interim Financial Reporting, to require disclosures regarding the fair value of financial instruments in interim financial statements. FSP FAS 107-1 and APB 28-1 was effective for interim periods ending after June 15, 2009. SPS implemented FSP FAS 107-1 and APB 28-1 on April 1, 2009, and the implementation did not have a material impact on its financial statements.  For FSP FAS 107-1 and APB 28-1 required disclosures, see Note 9 to the financial statements.

Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly (FSP FAS 157-4) —In April 2009, the FASB issued FSP FAS 157-4, which provides additional guidance for estimating fair value in accordance with SFAS No. 157, Fair Value Measurements, when the volume and level of market activity for an asset or liability have significantly decreased.  FSP FAS 157-4 emphasizes that even if there has been a significant decrease in the volume and level of market activity for the asset or liability, fair value still represents the exit price in an orderly transaction between market participants.  FSP FAS 157-4 was effective for interim and annual periods ending after June 15, 2009.  SPS implemented FSP FAS 157-4 on April 1, 2009, and the implementation did not have a material impact on its financial statements.

Recognition and Presentation of Other-Than-Temporary Impairments (FSP FAS 115-2 and FAS 124-2) —In April 2009, the FASB issued FSP FAS 115-2 and FAS 124-2, which changes the method for determining whether an other-than-temporary impairment exists for debt securities, and also requires additional disclosures regarding other-than-temporary impairments.  FSP FAS 115-2 and FAS 124-2 was effective for interim and annual periods ending after June 15, 2009.  SPS implemented FSP FAS 115-2 and FAS 124-2 on April 1, 2009, and the implementation did not have a material impact on its financial statements.

Subsequent Events (SFAS No. 165) — In May 2009, the FASB issued SFAS No. 165, which establishes general standards of accounting and disclosure for events that occur after the balance sheet date but before financial statements are issued. The accounting guidance contained in SFAS No. 165 is consistent with the auditing literature widely used for accounting and disclosure of subsequent events, however, SFAS No. 165 requires an entity to disclose the date through which subsequent events have been evaluated.  SFAS No. 165 was effective for interim and annual periods ending after June 15, 2009.  SPS implemented SFAS No. 165 on April 1, 2009, and the implementation did not have a material impact on its financial statements.

Recently Issued

Employers’ Disclosures about Postretirement Benefit Plan Assets (FSP FAS 132(R)-1) — In December 2008, the FASB issued FSP FAS 132(R)-1, which amends SFAS No. 132 (revised 2003), Employers’ Disclosures about Pensions and Other Postretirement Benefits, to expand an employer’s required disclosures about plan assets of a defined benefit pension or other postretirement plan to include investment policies and strategies, major categories of plan assets, information regarding fair value measurements, and significant concentrations of credit risk.  FSP FAS 132(R)-1 is effective for fiscal years ending after Dec. 15, 2009.  SPS does not expect the implementation of FSP FAS 132(R)-1 to have a material impact on its financial statements.

Amendments to FASB Interpretation No. 46(R) (SFAS No. 167) — In June 2009, the FASB issued SFAS No. 167, which amends the consolidation guidance applicable to variable interest entities. The amendments will significantly affect various elements of consolidation guidance under FASB Interpretation No. 46(R), including guidance for determining whether an entity is a variable interest entity and whether an enterprise is a variable interest entity’s primary beneficiary.  SFAS No. 167 is effective for fiscal years beginning after Nov. 15, 2009.  SPS is currently evaluating the impact of SFAS No. 167 on its financial statements.

The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles — a replacement of FASB Statement No. 162 (SFAS No. 168) — In June 2009, the FASB issued SFAS No. 168, which confirms that the FASB Accounting Standards Codification (Codification) will become the single source of authoritative GAAP, other than the guidance put forth by the SEC.  All other accounting literature not included in the Codification will be considered non-authoritative. SFAS No. 168 is effective for interim and annual periods ending after Sept. 15, 2009. SPS expects the implementation of SFAS No. 168 to have no impact on its financial statements.

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3.   Selected Balance Sheet Data

(Thousands of Dollars)	June 30, 2009			Dec. 31, 2008
Accounts receivable, net
Accounts receivable	$	61,536		$	67,706
Less allowance for bad debts	(4,504		)	(4,688		)
	$	57,032		$	63,018
Inventories
Materials and supplies	$	16,958		$	15,422
Fuel	3,605			31,660
	$	20,563		$	47,082
Property, plant and equipment, net
Electric plant	$	3,701,242		$	3,594,885
Construction work in progress	79,772			102,508
Total property, plant and equipment	3,781,014			3,697,393
Less accumulated depreciation	(1,594,474		)	(1,555,757		)
	$	2,186,540		$	2,141,636

4.     Income Taxes

Accounting for Uncertainty in Income Taxes — an interpretation of FASB Statement No. 109 (FIN 48)— SPS is a member of the Xcel Energy affiliated group that files consolidated income tax returns.

Federal Audit — In the first quarter of 2008, the Internal Revenue Service (IRS) completed an examination of Xcel Energy’s federal income tax returns for 2004 and 2005 (and research credits for 2003). The IRS did not propose any material adjustments for those tax years. Tax year 2004 is the earliest open year and the statute of limitations applicable to Xcel Energy’s 2004 federal income tax return remains open until Dec. 31, 2009.  In the third quarter of 2008, the IRS commenced an examination of tax years 2006 and 2007. As of June 30, 2009, the IRS had not proposed any material adjustments to tax years 2006 and 2007.

State Audits — In the first quarter of 2008, the state of Texas concluded an income tax audit through tax year 2005.  No material adjustments were proposed for this audit. As of June 30, 2009, SPS’ earliest open tax year for which an audit can be initiated by state taxing authorities under applicable statutes of limitations is 2004. There currently are no state income tax audits in progress.

Unrecognized Tax Benefits — The amount of unrecognized tax benefits was $3.7 million and $3.5 million on June 30, 2009 and Dec. 31, 2008, respectively. The unrecognized tax benefit amounts were increased by a payable associated with net operating loss (NOL) and tax credit carryovers of $0.8 million on June 30, 2009.  The tax benefits associated with NOL and tax credit carryovers were not material as of Dec. 31, 2008.

The unrecognized tax benefit balance included $0.3 million of tax positions on both June 30, 2009 and Dec. 31, 2008, which if recognized would affect the annual effective tax rate. In addition, the unrecognized tax benefit balance included $3.4 million and $3.2 million of tax positions on June 30, 2009 and Dec. 31, 2008, respectively, 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 effective tax rate but would accelerate the payment of cash to the taxing authority to an earlier period.

The decrease in the unrecognized tax benefit balance was not material from April 1, 2009 to June 30, 2009.  SPS’ amount of unrecognized tax benefits could significantly change in the next 12 months as the IRS audit progresses and when state audits resume. At this time, due to the uncertain nature of the audit process, it is not reasonably possible to estimate an overall range of possible change.

The amount of interest expense related to unrecognized tax benefits reported within interest charges in the second quarter of 2009 and 2008 was not material. The liability for interest related to unrecognized tax benefits was $0.3 million on both June 30, 2009 and Dec. 31, 2008.

No amounts were accrued for penalties as of June 30, 2009 and Dec. 31, 2008.

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5.     Rate Matters

Except to the extent noted below, the circumstances set forth in Note 13 to the financial statements included in SPS’ Annual Report on Form 10-K for the year ended Dec. 31, 2008 appropriately represent, in all material respects, the current status of other rate matters, and are incorporated herein by reference. The following disclosure includes unresolved proceedings that are material to SPS’ financial position.

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

Base Rate

Texas Retail Base Rate Case — In June 2008, SPS filed a rate case with the PUCT seeking an annual rate increase of approximately $61.3 million, or approximately 5.9 percent.  Base revenues are proposed to increase by $94.4 million, while fuel and purchased power revenue would decline by $33.1 million, primarily due to fuel savings from the Lea Power Partners (LPP) purchase power agreement.

The rate filing is based on a 2007 test-year adjusted for known and measurable changes, a requested ROE of 11.25 percent, an electric rate base of $989.4 million and an equity ratio of 51.0 percent.  Interim rates of $18 million for costs associated with the LPP power purchase agreement went into effect in September 2008.

In January 2009, a settlement agreement was reached with various intervenors, which provided for a base rate increase of $57.4 million, a reduced depreciation expense of $5.6 million, allowed SPS to implement the transmission rider in 2009 and precludes SPS from filing to seek any other change in base rates until Feb. 15, 2010.  In January 2009, an administrative law judge (ALJ) approved interim rates effective Feb. 1, 2009.

On June 2, 2009, the PUCT issued its order approving the settlement.

John Deere Wind Complaint — In June 2007, several John Deere Wind Energy subsidiaries (JD Wind) filed a complaint against SPS disputing SPS’ payments to JD Wind for energy produced from the JD Wind projects.  SPS responded that the payments to JD Wind for energy produced from its qualifying facility (QF) are appropriate and in accordance with SPS’ filed tariffs with the PUCT.  On March 25, 2009, the ALJ issued a proposal for decision, which recommends that SPS payment methodology to JD Wind is proper and that JD Wind’s complaint be denied.    On May 1, 2009 the PUCT issued a final order denying JD Wind’s request for relief against SPS.  On June 25, 2009 JD Wind filed a petition for review of the final order in Texas District Court.  On July 9, 2009, SPS intervened to defend the PUCT’s order denying JD Wind’s requested relief.

Texas Jurisdictional Fuel Allocation Methodology — On May 28, 2009, SPS filed an application to revise the calculation of Texas retail jurisdictional fuel and purchased power expense, effective as of the start of the current fuel reconciliation period, which began in January 2008.  SPS has determined that its current method of calculating the monthly amount results in a material amount of unrecovered fuel and purchased power expense.  The application seeks approval for a revised methodology, which matches the fuel and purchased power expenses in a month with the fuel factor revenue received from each kilowatt-hour used that month.  For the period January 2008 through June 2009, the revised methodology would increase the amount of Texas retail jurisdictional fuel and purchased power cost to be recovered from customers by approximately $5.0 million.

The PUCT has referred this case to the State Office of Administrative Hearings (SOAH) for a contested case hearing.  No procedural schedule has yet been established.

Texas Transmission Cost Recovery Factor (TCRF) — On June 22, 2009, SPS filed a request to implement a TCRF with proposed revenues of $7.4 million annually.  The TCRF filing is based on changes in transmission investment for the period of Jan. 1, 2008 through April 30, 2009 and increases in FERC approved transmission costs for 2008.  The PUCT implemented rules in late 2007 allowing utilities to request a TCRF in between rate cases for costs of new transmission investment and FERC approved transmission costs.  This is SPS’ first filing under that rule.  SPS anticipates the PUCT to issue an order with rates effective by the end of 2009.  On July 20, 2009, the PUCT referred this case to the SOAH for a contested case proceeding.  A prehearing conference was scheduled for July 30, 2009 to establish a procedural schedule.

9

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

Base Rate

2008 New Mexico Retail Electric Rate Case —In December 2008, SPS filed with the NMPRC a request to increase electric rates in New Mexico by approximately $24.6 million, or 6.2 percent. The request is based on a historic test-year (split year based on the year-ending June 30, 2008), an electric rate base of $321 million, and an equity ratio of 50.0 percent and a requested ROE of 12.0 percent.  SPS also requested interim rates of $7.6 million per year to recover capacity costs of the Lea Power facility, which became operational in September 2008.

On March 26, 2009, the NMPRC approved a partial stipulated settlement between the parties that allows SPS to recover approximately $5.7 million of interim rates, effective May 1, 2009, through an LPP cost rider until the final rates from the remainder of the case are effective.

On May 28, 2009, the parties filed an uncontested stipulation that resolves all issues in the case.  Under the stipulation, SPS receives a base rate increase of $14.2 million, effective July 1, 2009.  SPS has agreed that Dec. 1, 2010 is the earliest date it will file its next base rate case, subject to a force majeure provision triggered by additional environmental compliance costs.

On July 14, 2009, the NMPRC issued an order approving the stipulation if the parties accept revisions requiring SPS to fund audits of its fuel and purchased power costs and its renewable energy certificate (REC) transactions, with SPS being able to recover the costs of the audits in rates and requiring SPS to provide the NMPRC with notice about certain REC prices.  Under the order, the NMPRC’s approval becomes effective automatically, without the need for a further NMPRC order, when the parties make their filing accepting the revisions or stating they do not oppose the revisions.   On July 15, 2009, SPS filed an amendment to the stipulation that stated SPS’ acceptance of the revisions and stating that the NMPRC staff and all intervenors accept or do not oppose the revisions.  SPS implemented the new rates on July 15, 2009.

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

Wholesale Rate Complaints — In November 2004, Golden Spread Electric, Lyntegar Electric, Farmer’s Electric, Lea County Electric, Central Valley Electric and Roosevelt County Electric, all wholesale cooperative customers of SPS, filed a rate complaint with the FERC alleging that SPS’ rates for wholesale service were excessive and that SPS had incorrectly calculated monthly fuel cost adjustment charges to such customers (the Complaint). Among other things, the complainants asserted that SPS had inappropriately allocated average fuel and purchased power costs to other wholesale customers, effectively raising the fuel cost charges to the complainants. Cap Rock Energy Corporation (Cap Rock), another full-requirements customer of SPS, Public Service Company of New Mexico (PNM) and Occidental Permian Ltd. and Occidental Power Marketing, L.P. (Occidental), SPS’ largest retail customer, intervened in the proceeding.

In May 2006, a FERC ALJ issued an initial decision in the proceeding. The ALJ found that SPS should recalculate its fuel and purchased economic energy cost adjustment clause (FCAC) billings for the period beginning Jan. 1, 1999, to reduce the fuel and purchased power costs recovered from the complaining customers by deducting the incremental fuel costs attributed to SPS’ sales of capacity and energy to other wholesale customers served under market-based rates during this period based on the view that such sales should be treated as opportunity sales made out of temporarily excess capacity. In addition, the ALJ made recommendations on a number of base rate issues including a 9.64 percent ROE.

Golden Spread Complaint Settlement  — In December 2007, SPS reached a settlement with Golden Spread (which now includes Lyntegar Electric) and Occidental regarding base rate and fuel issues raised in the complaint described above as well as a subsequent rate proceeding.  In December 2007, this comprehensive offer of settlement (the Settlement) was filed with the FERC.  On April 21, 2008, the FERC approved the Settlement, which resolved all issues that were the subject of the Complaint; implemented a formula rate and extended the term of its partial requirements sale to Golden Spread beginning 2012 at 500 MW and ramping down to 200 MW at the end of the new term in 2019.  The Settlement made the extended purchase contingent on certain state approvals.  Golden Spread agreed to hold SPS harmless from any future adverse regulatory treatment regarding the proposed sale and SPS agreed to contingent payments ranging from $3 million to a maximum of $12 million, payable in 2012, in the event that there is an adverse cost assignment decision or a failure to obtain state approvals. The NMPRC ALJ has recommended approval of the replacement power agreement.  SPS’ applications before the NMPRC and the PUCT are currently pending.

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Order on Wholesale Rate Complaints — In April 2008, the FERC issued its Order on the Complaint applied to the remaining non-settling parties.  The Order addresses base rate issues for the period from Jan. 1, 2005 through June 30, 2006, for SPS’ full requirements customers who pay traditional cost-based rates and requires certain refunds.

·Base Rates:  The FERC determined: (1) the ROE should be 9.33 percent; (2) rates should be based on a 12 CP allocator; and (3) the treatment of market based rate contracts in the test-year should be to credit revenues to the cost of service rather than allocating costs to the agreements. The revenue requirement established by the FERC results in proposed revenues that are estimated to be approximately $25 million, or approximately $6.9 million below the level charged to these customers during this 18-month period. Rates for full requirements customers, the New Mexico Cooperatives and Cap Rock, as well as an interruptible contract with PNM for the period beginning July 1, 2006, are the subject of settlements that have either been approved or are pending before the FERC.

·Fuel Clause:  The FERC determined that the method for calculating fuel and purchased energy cost charges to the complaining customer is to deduct from such costs incremental fuel and purchased energy costs, which it is attributing to SPS’ market based intersystem sales on the basis that these are “opportunity” sales under its precedent.  The FERC ordered that refunds of fuel cost charges based on this method of determining the FCAC should begin as of Jan. 1, 2005 (the refund effective date in the case).  The FERC ordered SPS to file a compliance filing calculating its refund obligation and implement the instructions in the order in calculating its FCAC charges going forward from that date.  While the order is subject to interpretation with respect to aspects of the calculation of the refund obligation, SPS does not expect its refund obligation to its full requirements customers from Jan. 1, 2005 through March 31, 2008, to exceed $11 million. PNM has filed a separate complaint that any refund obligation to PNM will be determined in that docket.  SPS is reviewing the Order and has not yet determined whether to seek rehearing.

·The FERC also ruled on two other FCA issues.  First, it required that wind contracts be evaluated on an individual contract basis rather than in aggregate.  Second, the FERC determined that an after-the-fact screen should be applied to all QF purchases to determine if they are economic.  While this review will require additional effort, it is not expected that this will result in additional refunds as all of the individual wind contracts as well as the QF purchases are typically economic when compared to market energy prices.

Several parties, including SPS, filed requests for rehearing on the order.  These requests are pending before the FERC.  In July 2008, SPS submitted its compliance report to the FERC.  In the report, SPS has calculated the base rate refund for the 18-month period to be equal to $6.1 million and the fuel refund to be equal to $4.4 million.  Several wholesale customers have protested the calculations.  Once the final refund amounts are approved by the FERC, interest will be added to the refund due to the full requirements customers.  As of June 30, 2009, SPS has accrued an amount sufficient to cover the estimated refund obligation.

On June 5, 2009, SPS, the New Mexico Cooperatives and Cap Rock filed a letter with FERC indicating that the parties had reached an agreement in principle regarding this matter and asked that the FERC not issue an order upon reconsideration to allow the parties an opportunity to formalize the Settlement and file it with the NMPRC.  SPS, the New Mexico Cooperatives and Cap Rock are now finalizing the settlement documents.  The FERC, after receiving comments from interested parties, is expected to consider the proposed settlement.  With this settlement, SPS will have settled with all of the complainants in the case.

SPS 2008 Wholesale Rate Case — In March 2008, SPS filed a wholesale rate case seeking an annual revenue increase of $14.9 million or an overall 5.14 percent increase, based on 12.20 percent requested ROE. Four New Mexico Cooperatives filed a motion for dismissal and protest in April 2008.

On May 30, 2008, the FERC conditionally accepted and suspended the rates and established hearing and settlement procedures.  The FERC granted a one-day suspension of rates instead of 180 days.  Lea Power achieved commercial operations in September 2008 and the proposed base rates of $9.9 million, based on a 10.25 percent ROE and a 12 CP demand allocator, became effective, subject to refund.

The parties reached a settlement in principle, and an uncontested settlement was filed with the FERC on April 23, 2009.  As a result of the settlement, SPS will receive an annual revenue increase of approximately $9.6 million or an overall percentage increase of 3.3 percent. SPS expects the FERC to approve the uncontested settlement.

SPS 2008 Transmission Formula Rate Case — In December 2007, Xcel Energy submitted an application to implement a transmission formula rate for the SPS zone of the Xcel Energy Open Access Transmission Tariff (OATT). The changed rates will affect all wholesale transmission service customers using the SPS transmission network under either the Southwest Power Pool, Inc. (SPP) Regional OATT or the Xcel Energy OATT.

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As filed, SPS’ transmission rates would be updated annually each July 1 based on SPS’ prior year actual costs and loads plus the revenue requirements associated with projected current year transmission plant additions. The proposed ROE was 12.7 percent, including a 50 basis point adder for SPS’ participation in the SPP Regional Transmission Organization (RTO). The proposed rates would provide first year incremental annual transmission revenue for SPS of approximately $5.5 million. In February 2008, the FERC accepted the proposed rates, suspending the effective date to July 6, 2008, and setting the rate filing for hearings and settlement procedures. The FERC granted a 50 basis point adder to the ROE that it will determine in this proceeding as a result of SPS’ participation in the SPP RTO. The filed rates, updated for 2007 actual costs and projected 2008 transmission plant additions, were placed into effect on July 6, 2008, subject to refund.

On July 1, 2009, SPS and the parties notified the ALJ that a settlement in principle had been reached on all issues except the ratemaking and rate design treatment of certain radial transmission lines under the SPP Regional OATT.  The settlement terms are not yet public.  The radial line issue remains in settlement discussions; if the parties do not reach a settlement in principle by Sept. 4, 2009, SPS expects the issue to be set for litigated proceedings.  The outcome of the litigation is not expected to have a material impact on SPS.

6.     Commitments and Contingent Liabilities

Except to the extent noted below, the circumstances set forth in Notes 13 and 14 to the financial statements in SPS’ Annual Report on Form 10-K for the year ended Dec. 31, 2008 and Note 5 to the financial statements in this Quarterly Report on Form 10-Q, appropriately represent, in all material respects, the current status of commitments and contingent liabilities and are incorporated herein by reference. The following include unresolved contingencies that are material to SPS’ financial position.

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 — 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, to which SPS is alleged to be a PRP that sent hazardous materials and wastes.  At June 30, 2009, the liability for the cost of remediating these sites was estimated to be $0.1 million.

Third Party and Other Environmental Site Remediation

Asbestos Removal — Some of SPS’ facilities contain asbestos.  Most asbestos will remain undisturbed until the facilities that contain it are demolished or renovated.  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 14 of the SPS Annual Report on Form 10-K for the year ended Dec. 31, 2008.  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 immaterial 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

American Clean Energy and Security Act (ACES) — On June 26, 2009, the U.S. House of Representatives passed ACES.  Key provisions include a federal cap-and-trade program to reduce greenhouse gas (GHG) emissions by 17 percent by 2020 and 83 percent by 2050 compared to 2005 levels, a national renewable energy standard, investments in new clean energy technologies and energy efficiency, and mandates for new energy-saving standards.  The U.S. Senate has delayed consideration of ACES until September 2009, during which time the bill could change considerably.  The ultimate impact of the bill on SPS therefore remains uncertain.

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Environmental Protection Agency (EPA) Proposed GHG Endangerment Finding — On April 17, 2009, the EPA issued a proposed finding that GHGs threaten public health and welfare.  This finding was in response to the U.S. Supreme Court’s decision in Massachusetts v. EPA, 549 U.S. 497 (2007), which held that GHGs are pollutants covered by the Clean Air Act (CAA) and required the EPA to determine whether emissions of GHGs from motor vehicles endanger public health or welfare.  The EPA’s proposed endangerment finding applies to the CAA’s mobile source program, and does not automatically trigger regulation under other provisions of the CAA that are applicable to stationary sources, such as power plants.  As such, the proposed endangerment finding, in and of itself, does not impact SPS.

Clean Air Interstate Rule (CAIR)— In March 2005, the EPA issued the CAIR to further regulate sulfur dioxide (SO2) and nitrogen oxide (NOx) emissions.  The objective of CAIR was to cap emissions of SO2 and NOx in the eastern United States, including Texas.  In July 2008, the U. S. Court of Appeals for the District of Columbia vacated CAIR and remanded the rule to EPA.  On Dec. 23, 2008, the court reinstated CAIR while the EPA develops new regulations in accordance with the court’s July opinion.

As currently written, CAIR has a two-phase compliance schedule, beginning in 2009 for NOx and 2010 for SO2, with a final compliance deadline in 2015 for both emissions. Under CAIR, each affected state will be allocated an emissions budget for SO2 and NOx that will result in significant emission reductions. It will be based on stringent emission controls and forms the basis for a cap-and-trade program. State emission budgets or caps decline over time. States can choose to implement an emissions reduction program based on the EPA’s proposed model program, or they can propose another method, which the EPA would need to approve.

Under CAIR’s cap-and-trade structure, SPS can comply through capital investments in emission controls or purchase of emission allowances from other utilities making reductions on their systems.  The remaining capital investments for NOx controls in the SPS region are estimated at $4.5 million. For 2009, the estimated NOx allowance compliance costs are $1.4 million to $2.0 million. Annual purchases of SO2 allowances are estimated in the range of $1.7 million to $7.7 million each year, beginning in 2013, for phase I.

Allowance cost estimates for SPS are based on fuel quality and current market data.SPS believes the cost of any required capital investment or allowance purchases will be recoverable from customers in rates.

Clean Air Mercury Rule (CAMR) — In March 2005, the EPA issued the CAMR, which regulated mercury emissions from power plants. The Texas Commission on Environmental Quality (TCEQ) has adopted by reference the EPA model program.  In February 2008, the U.S. Court of Appeals for the District of Columbia vacated CAMR, which impacts federal CAMR requirements but not necessarily state-only rules.   At this time, Texas has not adopted any state-only mercury requirements.

Regional Haze Rules — In June 2005, the EPA finalized amendments to the July 1999 regional haze rules. These amendments apply to the provisions of the regional haze rule that require emission controls, known as best available retrofit technology (BART), for industrial facilities emitting air pollutants that reduce visibility by causing or contributing to regional haze.  Some of SPS’ generating facilities will be subject to BART requirements.  Some of these facilities are located in regions where CAIR is effective. The TCEQ had determined that facilities may use CAIR as a substitute for BART for NOx and SO2.

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 of them. The ultimate outcome of these matters cannot presently be determined. Accordingly, the ultimate resolution of these matters could have a material adverse effect on SPS’ financial position and results of operations.

Environmental Litigation

Carbon Dioxide (CO2) Emissions Lawsuit — In July 2004, the attorneys general of eight states and New York City, as well as several environmental groups, filed lawsuits in U.S. District Court in the Southern District of New York against five utilities, including Xcel Energy, the parent company of SPS, to force reductions in CO2 emissions. The other utilities include American Electric Power Co., Southern Co., Cinergy Corp. and Tennessee Valley Authority. The lawsuits allege that CO2 emitted by each company is a public nuisance as defined under state and federal common law because it has contributed to global warming. 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 October 2004, Xcel Energy and the other defendants filed a motion to dismiss the lawsuit. On Sept. 19, 2005, the court granted the motion to dismiss on constitutional grounds. Plaintiffs filed an appeal to the U.S. Court of Appeals for the Second Circuit. In June 2007, the Court of Appeals issued an order requesting the parties to file a letter brief regarding the impact of the United States Supreme Court’s decision in Massachusetts v. EPA, 127 S.Ct. 1438 (April 2, 2007) on the issues raised by the parties on appeal. Among other things, in its decision in Massachusetts v. EPA, the United States Supreme Court held that CO2 emissions are a “pollutant” subject to regulation by

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the EPA under the CAA. In July 2007, in response to the request of the Court of Appeals, the defendant utilities filed a letter brief stating the position that the United States Supreme Court’s decision supports the arguments raised by the utilities on appeal. The Court of Appeals has taken the matter under advisement and is expected to issue an opinion in due course.

Comer vs. Xcel Energy Inc. et al. — In April 2006, Xcel Energy, the parent company of SPS, received notice of a purported class action lawsuit filed in U.S. District Court in the Southern District of Mississippi. The lawsuit names more than 45 oil, chemical and utility companies, including Xcel Energy, as defendants and alleges that defendants’ CO2 emissions “were a proximate and direct cause of the increase in the destructive capacity of Hurricane Katrina.” Plaintiffs allege in support of their claim, several legal theories, including negligence and public and private nuisance and seek damages related to the loss resulting from the hurricane. Xcel Energy believes this lawsuit is without merit and intends to vigorously defend itself against these claims. In August 2007, the court dismissed the lawsuit in its entirety against all defendants on constitutional grounds. In September 2007, plaintiffs filed a notice of appeal to the U.S. Court of Appeals for the Fifth Circuit. Oral arguments were presented to the Court of Appeals on Aug. 6, 2008. Pursuant to the court’s order of Sept. 26, 2008, re-argument was held on Nov. 3, 2008. No explanation was given for the order. The Court of Appeals has taken the matter under advisement.

Native Village of Kivalina vs. Xcel Energy Inc. et al. — In February 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, the parent company of SPS, and 23 other utilities, oil, gas and coal companies. The suit was brought on behalf of approximately 400 native Alaskans, the Inupiat Eskimo, who claim that defendants’ emission of CO2 and other GHGs contribute to global warming, which is harming their village. Plaintiffs claim that as a consequence, the entire village must be relocated at a cost of between $95 million and $400 million. Plaintiffs assert a nuisance claim under federal and state common law, as well as a claim asserting “concert of action” in which defendants are alleged to have engaged in tortious acts in concert with each other. Xcel Energy was not named in the civil conspiracy claim. Xcel Energy believes the claims asserted in this lawsuit are without merit and joined with other utility defendants in filing a motion to dismiss on June 30, 2008. The matter has now been fully briefed.  It is uncertain when the court will render a decision.

Lamb County Electric Cooperative (LCEC) — In 1995, LCEC petitioned the PUCT for a cease and desist order against SPS alleging SPS was unlawfully providing service to oil field customers in LCEC’s certificated area. In May 2003, the PUCT issued an order denying LCEC’s petition based on its determination that SPS in 1976 was granted a certificate to serve the disputed customers. LCEC appealed the decision to the Texas state court. In August 2004, the court affirmed the decision of the PUCT. In September 2004, LCEC appealed the decision to the Court of Appeals for the Third Supreme Judicial District. In November 2008, the Court of Appeals issued an opinion affirming the decision in favor of SPS.  In December 2008, LCEC filed a petition for review with the Supreme Court of Texas. On Feb. 27, 2009, the Supreme Court of Texas denied LCEC’s request for review.

In 1996, LCEC filed a suit for damages against SPS in the District Court in Lamb County, Texas, based on the same facts alleged in the petition for a cease and desist order at the PUCT.  This suit has been dormant since it was filed, awaiting a final determination of the legality of SPS providing electric service to the disputed customers.  The PUCT order from May 2003, which found SPS was legally serving the disputed customers, collaterally determines the issue of liability contrary to LCEC’s position in the suit.  Because the PUCT May 2003 order has now been affirmed, on June 16, 2009, LCEC filed a motion to dismiss this case.

7.     Short-Term Borrowings and Other Financing Instruments

Commercial Paper — At June 30, 2009 and Dec. 31, 2008, SPS had no commercial paper outstanding.  At June 30, 2009 and Dec. 31, 2008, SPS had board approval to issue up to $250 million of commercial paper.

Money Pool — Xcel Energy has established a utility money pool arrangement that allows for short-term loans between the utility subsidiaries and from the holding company to the utility subsidiaries at market-based interest rates. The utility money pool arrangement does not allow loans from the utility subsidiaries to the holding company. SPS has approval to borrow up to $100 million under the arrangement. At Dec. 31, 2008, SPS had money pool loans outstanding of $90.5 million with a weighted average interest rate of 3.48 percent.  At June 30, 2009, SPS had no money pool loans outstanding or money pool borrowings.

8.Derivative Instruments

Effective Jan. 1, 2009, SPS adopted SFAS No. 161, which requires additional disclosures regarding why an entity uses derivative instruments, the volume of an entity’s derivative activities, the fair value amounts recorded to the balance sheet for derivatives, the gains and losses on derivative instruments included in the statement of operations or deferred, and information regarding certain credit-risk-related contingent features in derivative contracts.

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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.  See additional information pertaining to the valuation of derivative instruments in Note 10 to the financial statements.

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 a specific period.  These derivative instruments are designated as cash flow hedges for accounting purposes.

At June 30, 2009, accumulated other comprehensive losses related to interest rate derivatives included $0.6 million of net losses expected to be reclassified into earnings during the next 12 months as the related hedged interest transactions impact earnings.

Accumulated other comprehensive losses related to interest rate derivatives reclassified into earnings during the three and six months ended June 30, 2009 were $0.3 million and $0.5 million, respectively.

At June 30, 2009, SPS had one unsettled interest rate swap outstanding with a notional amount of $25 million.  The interest rate swap is not designated as a hedging instrument, and as such, gains from changes in fair value of $1.3 million and $2.0 million for the three and six months ended June 30, 2009, respectively, were recorded to earnings.

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 June 30, 2009 and Dec. 31, 2008, SPS held no commodity derivatives.  Changes in the fair value of 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.

The following table shows the major components of derivative instruments valuation in the balance sheets:

	June 30, 2009				Dec. 31, 2008
(Thousands of Dollars)	Derivative Instruments Valuation - Assets		Derivative Instruments Valuation - Liabilities		Derivative Instruments Valuation - Assets		Derivative Instruments Valuation - Liabilities
Long term purchased power agreements	$	81,014	$	54,037	$	85,477	$	55,831
Interest rate derivatives	—		6,494		—		8,503
Total	$	81,014	$	60,531	$	85,477	$	64,334

In 2003, as a result of FASB Statement 133 Implementation Issue No. C20, 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’s accumulated other comprehensive income, included as a component of common stockholder’s equity, is detailed in the following table:

	Three months ended June 30,
(Thousands of Dollars)	2009			2008
Accumulated other comprehensive loss related to cash flow hedges at April 1	$	(5,400	)	$	(6,704	)
After-tax net unrealized gains related to derivatives accounted for as hedges	—			751
After-tax net realized losses on derivative transactions reclassified into earnings	161			43
Accumulated other comprehensive loss related to cash flow hedges at June 30	$	(5,239	)	$	(5,910	)

	Six months ended June 30,
(Thousands of Dollars)	2009			2008
Accumulated other comprehensive loss related to cash flow hedges at Jan. 1	$	(5,559	)	$	(6,005	)
After-tax net unrealized gains related to derivatives accounted for as hedges	—			9
After-tax net realized losses on derivative transactions reclassified into earnings	320			86
Accumulated other comprehensive loss related to cash flow hedges at June 30	$	(5,239	)	$	(5,910	)

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Credit Related Contingent Features — If the credit rating of SPS were downgraded below investment grade, the counterparty to an interest rate swap agreement with SPS would have the ability to terminate the contract, which at June 30, 2009, would have resulted in the payment of the fair value of the derivative liability to the counterparty of approximately $6.5 million. There was no collateral posted on this contract at June 30, 2009.

Certain of SPS’s derivative instruments may also be subject to contract provisions that contain adequate assurance clauses. These provisions allow counterparties to seek performance assurance, including cash collateral, in the event that SPS’s ability to fulfill its contractual obligations is reasonably expected to be impaired. As of June 30, 2009, SPS had no collateral posted related to adequate assurance clauses in derivative contracts.

9.      Financial Instruments

The estimated fair values of SPS’ recorded financial instruments are as follows:

	June 30, 2009				Dec. 31, 2008
(Thousands of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Other investments	$	268	$	268	$	290	$	290
Long-term debt, including current portion	922,285		943,504		1,022,123		1,001,703

The fair values of cash and cash equivalents, notes and accounts receivable and notes and accounts payable are not materially different from their carrying amounts.  The fair value of SPS’ long-term investments are estimated based on quoted market prices for those or similar investments.  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 June 30, 2009 and Dec. 31, 2008. 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.

Letters of Credit— SPS uses letters of credit, generally with terms of one year, to provide financial guarantees for certain operating obligations.  At June 30, 2009 and Dec. 31, 2008, there were $10.0 million and $11.6 million of letters of credit outstanding, respectively.  The contract amounts of these letters of credit approximate their fair values and are subject to fees determined in the marketplace.

10.  Fair Value Measurements

Effective Jan. 1, 2008, SPS adopted Fair Value Measurements (SFAS No. 157) for recurring fair value measurements.  SFAS No. 157 provides a single definition of fair value and requires enhanced disclosures about assets and liabilities measured at fair value. SFAS No. 157 establishes a hierarchal framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value. The three levels defined by the SFAS No. 157 hierarchy and examples of each level are as follows:

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

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

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

Cash equivalents recorded to the balance sheets consist of money market funds.  Money market funds are recorded at cost plus estimated accrued interest to approximate fair value.  Changes in the observed trading prices and liquidity of money market funds are also monitored as additional support for determining fair value, and losses are recorded in earnings if fair value falls below recorded cost.

SPS uses quoted prices, based primarily on observable benchmark interest rate forecasts, to measure the fair value of interest rate derivatives.

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The following tables present, for each of the SFAS No. 157 hierarchy levels, SPS’s assets and liabilities that are measured at fair value on a recurring basis:

	June 30, 2009
(Thousands of Dollars)	Level 1		Level 2		Level 3		Net Balance
Assets
Cash equivalents	$	—	$	100,500	$	—	$	100,500
Liabilities
Interest rate derivatives	—		6,494		—		6,494

	Dec. 31, 2008
(Thousands of Dollars)	Level 1		Level 2		Level 3		Net Balance
Assets
Cash equivalents	$	—	$	50,000	$	—	$	50,000
Liabilities
Interest rate derivatives	—		8,503		—		8,503

11.  Interest and Other (Expenses) Income, Net

Interest and other (expenses) income, net, consisted of the following:

	Three months ended  June 30,					Six months ended  June 30,
(Thousands of dollars)	2009			2008		2009			2008
Interest (expenses) income	$	(89	)	$	1,207	$	192		$	2,033
Other nonoperating income	1			51		5			98
Insurance policy (expenses) income	(224		)	109		(144		)	99
Other nonoperating expenses	(11		)	—		(11		)	—
Total interest and other (expenses) income, net	$	(323	)	$	1,367	$	42		$	2,230

12.Segment Information

SPS has one reportable segment.  SPS operates in the regulated electric industry, providing wholesale and retail electric service in the states of Texas and New Mexico.  Revenues from external customers were $328.1 million and $537.9 million for the three months ended June 30, 2009 and 2008, respectively, and $697.1 million and $956.7 million for the six months ended June 30, 2009 and 2008, respectively.

13.Comprehensive Income

The components of total comprehensive income are shown below:

	Three months ended June 30,				Six months ended June 30,
(Thousands of Dollars)	2009		2008		2009		2008
Net income	$	16,808	$	3,970	$	25,990	$	2,705
Other comprehensive income:
After-tax net unrealized gains related to derivatives accounted for as hedges	—		751		—		9
After-tax net realized losses on derivative transactions reclassified into earnings	161		43		320		86
Other comprehensive income	161		794		320		95
Comprehensive income	$	16,969	$	4,764	$	26,310	$	2,800

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14.  Benefit Plans and Other Postretirement Benefits

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

Components of Net Periodic Benefit Cost (Credit)

	Three months ended June 30,
	2009			2008			2009			2008
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Xcel Energy Inc.
Service cost	$	16,744		$	14,929		$	1,057		$	1,211
Interest cost	43,046			44,677			13,050			12,894
Expected return on plan assets	(64,909		)	(68,697		)	(5,993		)	(8,425		)
Amortization of transition obligation	—			—			3,726			3,644
Amortization of prior service cost (credit)	6,154			5,166			(711		)	(544		)
Amortization of net loss	3,299			3,511			4,779			3,031
Net periodic benefit cost (credit)	4,334			(414		)	15,908			11,811
(Cost) credits not recognized and additional cost recognized due to the effects of regulation	(959		)	1,925			973			973
Net benefit cost recognized for financial reporting	$	3,375		$	1,511		$	16,881		$	12,784
SPS
Net benefit (credit) cost recognized for financial reporting	$	(1,544	)	$	(2,486	)	$	1,309		$	866

	Six months ended June 30,
	2009			2008			2009			2008
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Xcel Energy Inc.
Service cost	$	32,730		$	31,702		$	2,333		$	2,675
Interest cost	84,895			85,260			25,206			25,440
Expected return on plan assets	(128,269		)	(137,169		)	(11,388		)	(15,925		)
Amortization of transition obligation	—			—			7,222			7,288
Amortization of prior service cost (credit)	12,309			10,332			(1,363		)	(1,088		)
Amortization of net loss	6,228			6,370			9,665			5,749
Net periodic benefit cost (credit)	7,893			(3,505		)	31,675			24,139
(Cost) credits not recognized and additional cost recognized due to the effects of regulation	(1,446		)	4,517			1,946			1,946
Net benefit cost recognized for financial reporting	$	6,447		$	1,012		$	33,621		$	26,085
SPS
Net benefit (credit) cost recognized for financial reporting	$	(3,322	)	$	(5,240	)	$	2,500		$	1,741

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).

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Forward-Looking Information

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.  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 the availability of credit and its impact on capital expenditures and the ability of SPS to obtain financing on favorable terms; business conditions in the energy industry; actions of credit rating agencies; competitive factors, including the extent and timing of the entry of additional competition in the markets served by SPS; unusual weather; effects of geopolitical events, including war and acts of terrorism; 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; actions of accounting regulatory bodies; the items described under Factors Affecting Results of Continuing 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, 2008 and Exhibit 99.01 to this report on Form 10-Q for the quarter ended June 30, 2009.

Market Risks

SPS is exposed to market risks, including changes in commodity prices and interest rates, as disclosed in Item 7A, Quantitative and Qualitative Disclosures About Market Risk, in its Annual Report on Form 10-K for the year ended Dec. 31, 2008.  Commodity price and interest rate risks for SPS are mitigated in most jurisdictions due to cost-based rate regulation.

Continued distress in the financial markets may impact the fair value of the debt and equity securities in pension and postretirement health care plan trusts, as well as SPS’s ability to earn a return on short-term investments of excess cash.  As of June 30, 2009, there have been no material changes to market risks from that set forth in SPS’ Annual Report on Form 10-K for the year ended Dec. 31, 2008.

Results of Operations

SPS’ net income was approximately $26.0 million for the first six months of 2009, compared with net income of approximately $2.7 million for the first six months of 2008.

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 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, dramatic changes in costs or periods of extreme temperatures can impact earnings.

Electric —The following tables detail the electric revenues and margin:

	Six Months Ended June 30,
(Millions of Dollars)	2009			2008
Electric revenues	$	697		$	957
Electric fuel and purchased power	(444		)	(748		)
Electric margin	$	253		$	209

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

Electric Revenues

(Millions of Dollars)	2009 vs. 2008
Fuel and purchased power cost recovery	$	(335	)
Retail rate increases (Texas and New Mexico)	21
2008 fuel cost allocation regulatory accruals	12
Firm wholesale	9
Transmission revenues	6
Other, net	27
Total decrease in electric revenues	$	(260	)

Electric Margin

(Millions of Dollars)	2009 vs. 2008
Retail rate increases (Texas and New Mexico)	$	21
2008 fuel cost allocation regulatory accruals	12
Firm wholesale	9
Fuel and purchased power cost recovery	9
Transmission revenues	6
Purchased capacity costs	(22		)
Other, net	9
Total increase in electric margin	$	44

Non-Fuel Operating Expense and Other Items

Other Operating and Maintenance Expenses — Other operating and maintenance expenses for the first six months of 2009 increased $2.4 million, or 2.3 percent, compared to first six months of 2008.  The following summarizes the components of the changes for the six months ended June 30:

(Millions of Dollars)	2009 vs. 2008
Higher employee benefit costs	$	4
Higher plant generation costs	1
Lower consulting costs	(1		)
Lower material costs	(1		)
Other, net	(1		)
Total increase in other operating and maintenance expenses	$	2

Allowance for Funds Used During Construction, Debt and Equity (AFDC) — AFDC is a non-cash amount capitalized as a part of construction costs representing the cost of financing the construction.  Generally, these costs are recovered from customers, in future rates, as the related property is depreciated.  AFDC increased by approximately $2.3 million for the first six months of 2009 compared with 2008.  This increase was due to the debt to equity split that began in January of 2009.

Demand Side Management (DSM) — The DSM expenses for the first six months of 2009 decreased by approximately $1.7 million, or 29.8 percent, compared with 2008.  This decrease was due to the settlement of the Texas rate case in 2009 which extended the amortization period from 4 years to 10 years.

Interest Charges — Interest charges for the first six months of 2009 increased by approximately $6.2 million, or 22.6 percent, compared with 2008. The increase was primarily due to increased long-term debt levels necessary to repay short-term borrowings and to fund capital investments.

Income Taxes — Income tax expense increased by $12.7 million for the first six months of 2009 compared with 2008. The increase in income tax expense was primarily due to an increase in pretax income. The effective tax rate was 36.3 percent for the first six months of 2009, compared with 43.9 percent for the same period in 2008. The lower effective tax rate for the first six months of 2009 was primarily due to a lower forecasted annual effective tax rate for 2009 as compared to 2008.

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Public Utility Regulation

New Mexico Energy Efficiency Disincentive Rulemaking— During the last legislative session, increased energy efficiency goals and more affirmative disincentive language were adopted.  The NMPRC is currently conducting a rulemaking proceeding to update the energy efficiency rule, consistent with the legislative changes.  The NMPRC held an evidentiary hearing on the rule on June 26, 2009.  It is likely that the NMPRC will act on the proposed rule late in the third quarter or early in the fourth quarter of 2009.

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, 2008.  In addition to the matters discussed below, see Note 5 to the financial statements for a discussion of other regulatory matters.

Compliance with NERC Protective Maintenance Standards— In 2008, SPS filed self-reports with the SPP, the NERC Regional Entity for the SPS system, relating to failure to complete certain generation station battery tests, relay maintenance intervals and certain critical infrastructure protection standards.  SPS expects that penalties may be assessed by SPP in conjunction with some of the self-reports. The penalties are not expected to be material.

Item 4. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

SPS maintains a set of disclosure controls and procedures designed to ensure that information required to be disclosed in reports that it files or submits under the Securities Exchange Act of 1934 (Exchange Act) is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms. In addition, the disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in reports under the Exchange Act 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 the end of the period covered by this report, 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 our disclosure controls and 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 in this Quarterly Report on Form 10-Q for further discussion of legal proceedings, including Regulatory Matters and Commitments and Contingent Liabilities, which are hereby incorporated by reference. Reference also is made to Item 3 and Notes 13 and 14 of SPS’ financial statements in its Annual Report on Form 10-K for the year ended Dec. 31, 2008 for a description of certain legal proceedings presently pending.

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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, 2008, which is incorporated herein by reference.

We are subject to credit risks.

Credit risk includes the risk that our retail customers will not pay their bills, which may lead to a reduction in liquidity and an eventual increase in bad debt expense.  Retail credit risk is comprised of numerous factors including the overall economy and the price of products and services provided.

Credit risk also includes the risk that various counterparties that owe us money or product will breach their obligations. Should the counterparties to these arrangements fail to perform, we may be forced to enter into alternative arrangements. In that event, our financial results could be adversely affected and we could incur losses.

One alternative available to address counterparty credit risk is to transact on liquid commodity exchanges.  The credit risk is then socialized through the exchange central clearinghouse function.  While exchanges do remove counterparty credit risk, all participants are subject to margin requirements, which creates an additional need for liquidity to post margin as exchange positions change value daily.  Additional margin requirements could impact our liquidity.

SPS may at times have direct credit exposure in its short-term wholesale and commodity trading activity to various financial institutions trading for their own accounts or issuing collateral support on behalf of other counterparties.  SPS may also have some indirect credit exposure due to participation in organized markets such as the PJM Interconnection and MISO in which any credit losses are socialized to all market participants.

SPS does have additional indirect credit exposures to various financial institutions in the form of letters of credit provided as security by power suppliers under various long-term physical purchased power contracts.   If any of the credit ratings of the letter of credit issuers were to drop below the designated investment grade rating stipulated in the underlying long term purchased power contracts, the supplier would need to replace that security with an acceptable substitute.  If the security were not replaced, the party would be in technical default under the contract, which would enable SPS to exercise its contractual rights.

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

Legislative and regulatory responses related to climate change create financial risk.  Increased public awareness and concern may result in more regional and/or federal requirements to reduce or mitigate the effects of GHG.  Numerous states have announced or adopted programs to stabilize and reduce GHG and federal legislation has been introduced in both houses of Congress.  Likewise, the EPA has issued an Advanced Notice of Proposed Rulemaking that proposes to regulate GHGs under the Clean Air Act.  SPS’ 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.

Many of the federal and state climate change legislative proposals, such as ACES, 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 emissions allowances for their own operations.  Proponents of the cap and trade policy believe it will result in the most cost effective, flexible emission reductions. The impact of legislation and regulations, including a “cap and trade” structure, on SPS and its 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.  An important factor is SPS’ ability to recover the costs incurred to comply with any regulatory requirements that are ultimately imposed.  We may not recover all costs related to complying with regulatory requirements imposed on SPS.  If our regulators do not allow us to recover all or a part of the cost of capital investment or the operating and maintenance costs incurred to comply with the mandates, it could have a material adverse effect on our results of operations.

For further discussion see Note 6 to the financial statements.

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Item 6. EXHIBITS

* Indicates incorporation by reference

3.01*	Amended and Restated Articles of Incorporation dated Sept. 30, 1997 (Exhibit 3(a)(2) to Form 10-K (file no. 001-03789) dated March 3, 1998).
3.02*	By-laws dated Sept. 29, 1997 (Exhibit 3(b)(2) to Form 10-K (file no. 001-03789) dated March 3, 1998).
10.01*	Amendment dated as of April 13, 2009 to the SPS Credit Agreement dated as of Dec. 14, 2006 (Exhibit 10.04 of Form 10-Q of Xcel Energy dated July 31, 2009 (file no. 001-03034)).
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.

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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 on Aug. 3, 2009.

Southwestern Public Service Company

(Registrant)

/s/ TERESA S. MADDEN

Teresa S. Madden

Vice President and Controller

/s/ BENJAMIN G.S. FOWKE III

Benjamin G.S. Fowke III

Vice President and Chief Financial Officer

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