UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

x	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2008

o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

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		(I.R.S. Employer Identification No.)
incorporation or organization)

Tyler at Sixth,
Amarillo, Texas		79101
(Address of principal executive		(Zip Code)
offices)

Registrant’s telephone number, including area code (303) 571-7511

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 is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer o		Accelerated filer o

Non-accelerated filer x		Smaller reporting company o
(Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No x

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

Class		Outstanding at May 5, 2008
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.

PART 1. FINANCIAL INFORMATION

Item 1. Financial Statements

SOUTHWESTERN PUBLIC SERVICE CO.

STATEMENTS OF OPERATIONS (UNAUDITED)

(Thousands of Dollars)

	Three Months Ended March 31,
	2008			2007

Operating revenues	$	418,797		$	365,898

Operating expenses
Electric fuel and purchased power	321,692			264,407
Other operating and maintenance expenses	51,425			51,093
Depreciation and amortization	24,966			24,688
Taxes (other than income taxes)	10,323			11,562
Total operating expenses	408,406			351,750

Operating income	10,391			14,148

Interest and other income, net	863			803

Interest charges and financing costs
Interest charges — includes other financing costs of $591 and $585, respectively	13,931			13,034
Allowance for funds used during construction — debt	(656		)	(498		)
Total interest charges and financing costs	13,275			12,536

(Loss) income before income taxes	(2,021		)	2,415
Income taxes (benefit) expense	(756		)	750
Net (loss) income	$	(1,265	)	$	1,665

See Notes to Financial Statements

SOUTHWESTERN PUBLIC SERVICE CO.

STATEMENTS OF CASH FLOWS (UNAUDITED)

(Thousands of Dollars)

	Three Months Ended March 31,
	2008			2007
Operating activities
Net (loss) income	$	(1,265	)	$	1,665
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Depreciation and amortization	26,024			25,586
Deferred income taxes	4,491			(1,044		)
Amortization of investment tax credits	(55		)	(63		)
Net realized and unrealized hedging and derivative transactions	67			66
Changes in operating assets and liabilities:
Accounts receivable	3,420			8,577
Accrued unbilled revenues	2,711			(18,507		)
Recoverable electric energy costs	(19,683		)	56,253
Inventories	(3,357		)	(1,457		)
Prepayments and other	1,495			986
Accounts payable	42,092			(36,576		)
Net regulatory assets and liabilities	(171		)	(1,178		)
Other current liabilities	(13,065		)	(16,455		)
Change in other noncurrent assets	(2,761		)	(2,063		)
Change in other noncurrent liabilities	2,526			921
Net cash provided by operating activities	42,469			16,711

Investing activities
Utility capital/construction expenditures	(46,728		)	(29,223		)
Investments in utility money pool arrangement	—			(42,600		)
Receipts from utility money pool arrangement	—			42,600
Other investments	2,171			309
Net cash used in investing activities	(44,557		)	(28,914		)

Financing activities
Proceeds from (repayment of) short-term borrowings – net	(73,000		)	21,500
Borrowings under utility money pool arrangement	240,500			107,100
Repayments under utility money pool arrangement	(146,000		)	(97,900		)
Dividends paid to parent	(15,931		)	(18,581		)
Net cash provided by financing activities	5,569			12,119

Net increase (decrease) in cash and cash equivalents	3,481			(84		)
Cash and cash equivalents at beginning of period	714			297
Cash and cash equivalents at end of period	$	4,195		$	213

Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	14,104		$	6,793
Cash paid for income taxes (net of refunds received)	1,172			3,643

Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable	$	3,169		$	4,754

See the Notes to Financial Statements

SOUTHWESTERN PUBLIC SERVICE CO.

BALANCE SHEETS (UNAUDITED)

(Thousands of Dollars)

	March 31, 2008			Dec. 31, 2007
ASSETS
Current assets:
Cash and cash equivalents	$	4,195		$	714
Accounts receivable, net	67,062			67,254
Accounts receivable from affiliates	5,528			8,756
Accrued unbilled revenues	105,614			108,325
Recoverable electric energy costs	42,384			22,701
Inventories	20,700			17,343
Derivative instruments valuation	8,926			8,926
Prepayments and other	5,954			7,449
Deferred income taxes	779			2,970
Total current assets	261,142			244,438

Property, plant and equipment, net	2,061,429			2,043,426

Other assets:
Prepaid pension asset	121,001			117,948
Derivative instruments valuation	83,245			85,477
Regulatory assets	122,273			124,900
Other investments	299			2,470
Deferred charges and other	6,644			6,855
Total other assets	333,462			337,650
Total assets	$	2,656,033		$	2,625,514

LIABILITIES AND EQUITY
Current liabilities:
Current portion of long-term debt	$	100,000		$	—
Short-term debt	50,000			123,000
Borrowings under utility money pool arrangement	100,000			5,500
Accounts payable	189,138			153,130
Accounts payable to affiliates	11,443			9,432
Taxes accrued	9,939			22,902
Dividends payable to parent	15,822			15,931
Accrued interest	17,692			12,816
Derivative instruments valuation	4,811			4,468
Other	19,083			24,062
Total current liabilities	517,928			371,241

Deferred credits and other liabilities:
Deferred income taxes	463,400			462,228
Regulatory liabilities	130,828			133,025
Derivative instruments valuation	60,838			60,918
Asset retirement obligations	3,638			3,592
Deferred investment tax credits	2,940			2,995
Pension and employee benefit obligations	23,736			23,871
Other	10,568			7,458
Total deferred credits and other liabilities	695,948			694,087

Commitments and contingencies (see Note 6)
Capitalization:
Long-term debt	674,066			774,033
Common stock – authorized 200 shares of $1.00 par value, outstanding 100 shares	—			—
Additional paid in capital	503,066			503,066
Retained earnings	271,729			289,092
Accumulated other comprehensive loss	(6,704		)	(6,005		)
Total common stockholder’s equity	768,091			786,153
Total liabilities and equity	$	2,656,033		$	2,625,514

See the Notes to Financial Statements

SOUTHWESTERN PUBLIC SERVICE CO.

NOTES TO FINANCIAL STATEMENTS (UNAUDITED)

In the opinion of management, the accompanying unaudited financial statements contain all adjustments necessary to present fairly the financial position of SPS as of March 31, 2008, and Dec. 31, 2007; the results of its operations for the three months ended March 31, 2008 and 2007; and its cash flows for the three months ended March 31, 2008 and 2007. Due to the seasonality of electric sales of SPS, interim results are not necessarily an appropriate base from which to project annual results.

1. 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, 2007, appropriately represent, in all material respects, the current status of accounting policies and are incorporated herein by reference.

Fair Value Measurements —SPS presents interest rate derivatives at estimated fair values in its financial statements, utilizing broker quotes to establish fair value.

2. Recently Issued Accounting Pronouncements

Statement of Financial Accounting Standards (SFAS) No. 157 Fair Value Measurements (SFAS No. 157) — In September 2006, the Financial Accounting Standards Board (FASB) issued SFAS No. 157, which provides a single definition of fair value, together with a framework for measuring it, and requires additional disclosure about the use of fair value to measure assets and liabilities. SFAS No. 157 also emphasizes that fair value is a market-based measurement, and sets out a fair value hierarchy with the highest priority being quoted prices in active markets. Fair value measurements are disclosed by level within that hierarchy. SFAS No. 157 is effective for financial statements issued for fiscal years beginning after Nov. 15, 2007.

In February 2008, the FASB issued Effective Date of FASB Statement No. 157 (FASB Statement of Position (FSP) No. 157-2 (FSP No. 157-2)). FSP No. 157-2 delays the effective date of SFAS No. 157 until fiscal years beginning after Nov. 15, 2008, for fair value measurements of non-financial assets and non-financial liabilities, except for items that are recognized or disclosed at fair value in an entity’s financial statements on a recurring basis (at least annually).

As of Jan. 1, 2008, SPS adopted SFAS No. 157 for all assets and liabilities measured at fair value except for non-financial assets and non-financial liabilities measured at fair value on a non-recurring basis, as permitted by FSP No. 157-2. The adoption did not have a material impact on its financial statements. For additional discussion and SFAS No. 157 required disclosures see Note 9 to the financial statements.

The Fair Value Option for Financial Assets and Financial Liabilities - Including an Amendment of FASB Statement No. 115 (SFAS No. 159) — In February 2007, the FASB issued SFAS No. 159, which provides companies with an option to measure, at specified election dates, many financial instruments and certain other items at fair value that are not currently measured at fair value. A company that adopts SFAS No. 159 will report unrealized gains and losses on items, for which the fair value option has been elected, in earnings at each subsequent reporting date. This statement also establishes presentation and disclosure requirements designed to facilitate comparisons between entities that choose different measurement attributes for similar types of assets and liabilities. This statement is effective for fiscal years beginning after Nov. 15, 2007, effective Jan. 1, 2008. SPS adopted SFAS No. 159 and the adoption did not have a material impact on its financial statements.

Business Combinations (SFAS No. 141 (revised 2007)) — In December 2007, the FASB issued SFAS No. 141R, 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. 141R 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 will evaluate the impact of SFAS No. 141R on its financial statements for any potential business combinations subsequent to Jan. 1, 2009.

Disclosures about Derivative Instruments and Hedging Activities (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 of objectives and strategies for using derivatives, gains and losses on derivative instruments, and credit-risk-related contingent features in derivative agreements. SFAS No. 161 is effective for financial statements issued for fiscal years and interim periods beginning after Nov. 15, 2008, with early application encouraged. SPS is currently evaluating the impact adoption of SFAS No. 161.

Accounting for Deferred Compensation and Postretirement Benefit Aspects of Endorsement Split-Dollar Life Insurance Arrangements (Emerging Issues Task Force (EITF) Issue No. 06-4) — In June 2006, the EITF reached a consensus on EITF No. 06-4, which provides guidance on the recognition of a liability and related compensation costs for endorsement split-dollar life insurance policies that provide a benefit to an employee that extends to postretirement periods. Therefore, this EITF would not apply to a split-dollar life insurance arrangement that provides a specified benefit to an employee that is limited to the employee’s active service period with an employer. EITF No. 06-4 is effective for fiscal years beginning after Dec. 15, 2007, with earlier application permitted. Upon adoption of EITF 06-4 on Jan. 1, 2008, SPS recorded a liability of $0.3 million, net of tax, as a reduction of retained earnings. Thereafter, changes in the liability will be reflected in operating results.

Accounting for Income Tax Benefits of Dividends on Share-Based Payment Awards (EITF No. 06-11) — In June 2007, the EITF reached a consensus on EITF No. 06-11, which states that an entity should recognize a realized tax benefit associated with dividends on nonvested equity shares and nonvested equity share units charged to retained earnings as an increase in additional paid in capital. The amount recognized in additional paid in capital should be included in the pool of excess tax benefits available to absorb potential future tax deficiencies on share-based payment awards. EITF No. 06-11 should be applied prospectively to income tax benefits of dividends on equity-classified share-based payment awards that are declared in fiscal years beginning after Dec. 15, 2007. The adoption of EITF No. 06-11 did not have a material impact on SPS’ financial statements.

3. Selected Balance Sheet Data

(Thousands of Dollars)	March 31, 2008			Dec. 31, 2007
Accounts receivable, net:
Accounts receivable	$	70,256		$	70,420
Less allowance for bad debts	(3,194		)	(3,166		)
	$	67,062		$	67,254

Inventories:
Materials and supplies	$	15,169		$	14,039
Fuel	5,531			3,304
	$	20,700		$	17,343

Property, plant and equipment, net:
Electric utility plant	$	3,501,222		$	3,476,146
Construction work in progress	85,868			78,436
Total property, plant and equipment	3,587,090			3,554,582
Less accumulated depreciation	(1,525,661		)	(1,511,156		)
	$	2,061,429		$	2,043,426

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. In the first quarter of 2008, the 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, 2008.

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 March 31, 2008, SPS’ earliest open tax year in which an audit can be initiated by state taxing authorities under applicable statutes of limitations is 2003.

The amount of unrecognized tax benefits was $2.3 million and $2.5 million on Dec. 31, 2007 and March 31, 2008, respectively. These unrecognized tax benefit amounts were reduced by the tax benefits associated with tax credit carryovers of $0.1 million as of Dec. 31, 2007 and March 31, 2008.

The unrecognized tax benefit balance included $0.3 million and $0.3 million of tax positions on Dec. 31, 2007 and March 31, 2008, respectively, which if recognized would affect the annual effective tax rate. In addition, the unrecognized tax benefit balance included $2.0 million and $2.2 million of tax positions on Dec. 31, 2007 and March 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 increase in the unrecognized tax benefit balance of $0.2 million from Dec. 31, 2007 to March 31, 2008, was due to the addition of similar uncertain tax positions related to ongoing activity and the resolution of certain federal and state audit matters. SPS’ amount of unrecognized tax benefits could significantly change in the next 12 months when the IRS and state tax audits resume. However, at this time, it is not reasonably possible to estimate an overall range of possible change.

The liability for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with tax credit carryovers. The change in the interest expense liability from Dec. 31, 2007, to March 31, 2008, was not material. The liability for interest related to unrecognized tax benefits was $0.1 million on Dec. 31, 2007 and March 31, 2008. No amounts were accrued for penalties as of March 31, 2008.

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, 2007 appropriately represent, in all material respects, the current status of other rate matters, and are incorporated herein by reference. The following include unresolved proceedings that are material to SPS’ financial position.

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

Base Rate

Application to Increase Voltage-Level Line Loss Factors — In January 2008, the PUCT approved SPS’ application to update its current Texas retail fuel factors to reflect revised loss factors. Under the Texas retail base rate case, SPS was permitted to implement the revised line loss factors effective to May 2007. SPS recognized $6.2 million in the fourth quarter of 2007 for the impact of the revised line loss factors from May 1, 2007 through Dec. 31, 2007.

Electric and Resource Adjustment Clauses

Transmission Cost Recovery (TCR) Factor Rulemaking — The PUCT adopted, in November 2007, new rules relating to TCR factor outside of a base rate case. The rule establishes the mechanism by which SPS can request annual recovery of its reasonable and necessary expenditures for transmission infrastructure improvement costs and changes in wholesale transmission charges that are not included in existing rates. This new rule allows SPS more timely recovery of transmission cost increases in-between base rate cases.

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

Base Rate

New Mexico Electric Rate Case — On July 30, 2007, SPS filed a request for a retail electric general rate increase of $17.3 million annually, or 6.6 percent, with the NMPRC. The rate filing is based on 2006 historic test year adjusted for known and measurable changes and includes a requested return on equity (ROE) of 11.0 percent, an electric rate base of approximately $307.3 million and an equity ratio of 51.2 percent.

Following is a summary of intervenor and NMPRC staff testimony, which was filed on March 6, 2008.

· Staff recommended an increase of approximately $8 million based on a 9.1 percent ROE and other adjustments.

· The attorney general recommended a $2 million rate decrease based on a 9.2 percent ROE and other adjustments.

· Occidental Permian, a large retail customer, recommended a 9.9 percent ROE.

Hearings were held in April 2008. At the close of the hearings, the parties agreed to move consideration of the Lea Power Partners (Lea Power) rider costs to a future rate proceeding to be initiated by Xcel Energy this summer, which will be accompanied with a request for interim relief, so that issues associated with lease accounting and potential contract restructuring, discussed in the Management’s Discussion and Analysis section of this report, may be adequately addressed. The remaining procedural schedule follows:

·		Recommend decision		June 30, 2008
·		Final order		Aug. 29, 2008

Electric and Resource Adjustment Clauses

New Mexico Fuel Factor Continuation Filing — In August 2005, SPS filed with the NMPRC requesting continuation of the use of SPS’ fuel and purchased power cost adjustment clause (FPPCAC) and current monthly factor cost recovery methodology. This filing was required by NMPRC rule.

Testimony was filed in the case by staff and intervenors objecting to SPS’ assignment of system average fuel costs to certain wholesale sales and the inclusion of certain purchased power capacity and energy payments in the FPPCAC. The testimony also proposed limits on SPS’ future use of the FPPCAC. Related to these issues, some intervenors requested disallowances for past periods, which in the aggregate total approximately $45 million. This claim was for the period from Oct. 1, 2001 through May 31, 2005 and does not include the value of incremental cost assigned for wholesale transactions from that date forward. Other issues in the case include the treatment of renewable energy certificates and sulfur dioxide (SO₂)allowance credit proceeds in relation to SPS’ New Mexico retail fuel and purchased power recovery clause.

In December 2007, SPS, the NMPRC, Occidental Permian Ltd. and the New Mexico Industrial Energy Consumers (NMIEC) filed an uncontested settlement of this matter with the NMPRC.

· The settlement resolves all issues in the fuel continuation proceeding for total consideration of $15 million, which includes customer refunds of $11.7 million.

· At Dec. 31, 2007, a reserve had been previously established for this potential exposure, with no further expense accrual required, assuming this settlement is approved.

· The settlement would also provide for significantly greater certainty surrounding system average fuel cost assignment on a going forward basis and reduce percentages of system average cost wholesale sales between now and 2019 on a stepped down basis.

· Under the terms of the settlement, SPS anticipates additional fuel cost disallowances in 2008 and a portion of 2009 of approximately $2 million per year. It does not anticipate any future disallowances beyond this period.

· Finally, the settlement provides for SPS to continue its use of the FPPCAC subject to additional reporting provisions.

A hearing on the merits of the settlement was held in April 2008. The parties are to provide the hearing examiner with a proposed certification of the settlement on May 2, 2008, which will recommend approval of the settlement. Any objections to the proposed certification are due on May 9, 2008.

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 to them 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 complainant asserted that SPS had inappropriately allocated average fuel and purchased power costs to its other wholesale customers, effectively raising the fuel cost charges to 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 administrative law judge (ALJ) issued an initial decision in the proceeding. The ALJ found that SPS should recalculate its wholesale 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 from such costs the incremental fuel costs attributed to SPS’ sales of system firm capacity and associated 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 and the use of a 3-month coincident peak (3CP) demand allocator.

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 with a minor modification to the formula rate proposed by the FERC and accepted by the parties. The Settlement provides for:

· A $1.25 million payment by SPS to Golden Spread related to resolve a dispute concerning the quantities Golden Spread was entitled to take under its existing partial requirements agreement for the years 2006 and 2007. The Settlement caps those quantities for the period 2008 through 2011. SPS is not required to make any fuel refunds to Golden Spread that were the subject of the Complaint under the terms of the Settlement.

· An extended partial requirements contract at system average cost, with a capacity amount that ramps down over the period 2012 through 2019 from 500 MW to 200 MW. The extended agreement requires that the cost assignment treatment receive Texas and New Mexico state approvals and provides for alternative pricing terms and quantities to hold SPS harmless from cost disallowances in the event that adverse regulatory treatment occurs or state approvals are not obtained. 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.

· Resolution of base rates in the Complaint without any adjustment to the existing rates for the period January 2005 through June 30, 2006. The Settlement also resolves all base rate issues in SPS’ subsequent rate proceeding for the period July 1, 2006 through June 30, 2008, other than the method to be used to allocate demand related costs and provided for two sets of agreed on rates that are dependent on the ultimate resolution of that issue. If SPS prevails in its support of the 12 month coincident peak (12 CP) demand allocation method, there would be no impact to earnings for this period. If Golden Spread prevails, SPS would be required to refund Golden Spread and PNM approximately $4 million for the period through the end of 2007.

· For July 1, 2008 and beyond, Golden Spread will be under a formula rate for power supply service. The rate will be based on actual data the most recent historic year adjusted for known and measurable changes and trued up to the actual performance in the subsequent calendar year. Initially, the formula will be based on a 10.25 percent ROE and either party will have a right to seek changes to the ROE beginning with the 2009 formula rate filing. SPS and Golden Spread will share margins from its sales to West Texas Municipal Power Agency (WTMPA) and El Paso Electric (EPE) in that year but will assign system average fuel and energy costs to those agreements for purposes of calculating Golden Spread’s monthly fuel cost.

Order on Wholesale Rate Complaints — On April 21, 2008, the FERC issued its Order on the Complaint (the Order) 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 return on equity 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 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 in July 1, 2006, are the subject of settlements that have either been approved or are pending before FERC. These settlements are described in Wholesale 2005 Power Base Rate Application below.

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 within 30 days of the date of the Order 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 Qualifying Facility (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 the all of the individual wind contracts as well as the QF purchases are typically economic when compared to market energy prices.

As of March 31, 2008, SPS has accrued for an amount, which it believes is sufficient to cover the refund obligation.

Wholesale 2005 Power Base Rate Application — In December 2005, SPS filed for a $2.5 million increase in wholesale power rates to certain electric cooperatives. In January 2006, the FERC conditionally accepted the proposed rates for filing and the $2.5 million power rate increase became effective on July 1, 2006, subject to refund. The FERC also set the rate increase request for hearing and settlement judge procedures. In September 2006, offers of settlement with respect to the five full-requirements customers and with respect to PNM were filed for approval. In September 2007, the FERC accepted the settlement with the full-requirements customers. The PNM settlement is still pending before the FERC.

As noted, the Wholesale 2005 Power Base Rate Application relating to Golden Spread was settled in conjunction with the Complaint Settlement discussed above. Therefore, SPS has settled with all parties in the Wholesale 2005 Power Base Rate Application except for resolution with Golden Spread of the demand cost allocation methodology . A hearing on the demand allocation methodology has been set for July 29, 2008. An initial decision is expected by the end of September 2008.

SPS Formula Transmission 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 Southwest Power Pool, Inc. (SPP) made a companion filing in January 2008, to implement the same pricing in the SPS zone of the SPP regional OATT. The changed rates will affect all wholesale transmission service customers using the SPS transmission network under either the SPP Regional OATT or the Xcel Energy OATT.

A formula rate will help facilitate the financing and construction of the new transmission facilities while providing an adequate rate of return on invested capital. The proposed 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 rate of return on common equity is 12.7 percent, including a 50 basis point adder for SPS’ participation in the SPP Regional Transmission Organization, consistent with FERC precedent. The proposed rates would provide first year incremental annual transmission revenue for SPS of approximately $5.5 million.

In February 2008, the FERC issued an order accepting 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 regional transmission organization. In March 2008, the FERC accepted the companion SPP rate change filing subject to the outcome of the SPS rate filing. The SPS and SPP rate filings are now in settlement procedures. The ultimate outcome of the rate filings is not known at this time.

SPS 2008 Wholesale Rate Case — On March 31, 2008, SPS filed a wholesale power base rate case in the full-requirements customers’ base rates. SPS is seeking an annual revenue increase of $14.9 million or an overall 5.14 percent increase, based on 12.20 percent requested ROE. On April 21, 2008, a motion for dismissal and protest was filed by the four eastern New Mexico cooperatives. A FERC decision is expected later in 2008.

6. Commitments and Contingencies

Except to the extent noted below, 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, 2007 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 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 and some other parties have caused environmental contamination. At March 31, 2008, SPS was a party to third party and other sites, such as landfills, to which SPS is alleged to be a potentially responsible party (PRP) that sent hazardous materials and wastes.

SPS records a liability when enough information is obtained to develop an estimate of the cost of environmental remediation and revises the estimate as information is received. The estimated remediation cost may vary materially from the initial estimate.

To estimate the remediation cost for these sites, assumptions are made when facts are not fully known. For instance, assumptions may be made about the nature and extent of site contamination, the extent of required cleanup efforts, costs of alternative cleanup methods and pollution-control technologies, the period over which remediation will be performed and paid for, changes in environmental remediation and pollution-control requirements, the potential effect of technological improvements, the number and financial strength of other PRPs and the identification of new environmental cleanup sites.

Estimates are revised as facts become known. At March 31, 2008, the liability for the cost of remediating these sites was estimated to be $0.1 million. Some of the cost of remediation may be recovered from:

· Insurance coverage;

· Other parties that have contributed to the contamination; and

· Customers.

Neither the total remediation cost nor the final method of cost allocation among all PRPs of the unremediated sites has been determined. Estimates have been recorded for SPS’ future costs for these sites.

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 12 of the SPS Annual Report on Form 10-K for the year ended Dec. 31, 2007. 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

Clean Air Interstate Rule — In March 2005, the Environmental Protection Agency (EPA) issued the Clean Air Interstate Rule (CAIR) to further regulate SO₂ and nitrogen oxide (NOx) emissions. The objective of CAIR is to cap emissions of SO₂ and NOx in the eastern United States, including Texas. CAIR addresses the transportation of fine particulates, ozone and emission precursors to nonattainment downwind states. 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.

In July 2005, SPS, the City of Amarillo, Texas and Occidental Permian LTD filed a lawsuit against the EPA and a request for reconsideration with the agency to exclude West Texas from the CAIR. El Paso Electric Co. joined in the request for reconsideration. Xcel Energy and SPS advocated that West Texas should be excluded from CAIR because it does not contribute significantly to nonattainment with the fine particulate matter standards in any downwind jurisdiction.

In March 2006, the EPA denied the petition for reconsideration. On June 27, 2006, Xcel Energy and the other parties filed a petition for review of the denial of the petition for reconsideration, as well as a petition for review of the Federal Implementation Plan, with the D.C. Circuit Court of Appeals. The Court has taken this matter under advisement and a decision is expected in due course.

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. Based on the preliminary analysis of various scenarios of capital investment and allowance purchase, SPS currently believes that after the installation of low NOx burners on Harrington 3 in 2006, the remaining capital investments for NOx controls in the SPS region are estimated at $12 million. Purchases of NOx allowances are estimated at $2.1 million in 2009 with no NOx allowance needs in 2010. Annual purchases of SO₂ allowances are estimated in the range of $5 million to $25 million each year, beginning in 2012 for phase I, based on allowance costs and fuel quality as of March 2007. These cost estimates represent one potential scenario on complying with CAIR, if West Texas is not excluded.

While SPS expects to comply with the new rules through a combination of additional capital investments in emission controls at various facilities and purchases of emission allowances, it is continuing to review the alternatives. SPS believes the cost of any required capital investment or allowance purchases will be recoverable from customers in rates.

Clean Air Mercury Rule — In March 2005, the EPA issued the Clean Air Mercury Rule (CAMR), which regulated mercury emissions from power plants. The Texas Commission of Environmental Quality (TCEQ) has adopted by reference the EPA model program. In February 2008, the D.C. Circuit Court of Appeals vacated CAMR, which impacts federal CAMR requirements but not necessarily state-only rules. Given the many uncertainties created by the court’s opinion, it is not possible at this time to provide an accurate summary of applicable federal mercury requirements or cost estimates.

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 has determined that facilities may use CAIR as a substitute for BART for NOx and SO₂. If West Texas is excluded from CAIR by the D.C. Circuit Court of Appeals, then these facilities will be subject to BART requirements for NOx, SO₂ and particulate matter. Due to the uncertainties of the litigation outcome, SPS is not able to estimate the cost impact at this time.

Maddox Station Groundwater — The New Mexico Environment Department (NMED) is requiring wastewater activity at Maddox Station to be permitted. SPS is developing the permit application and engineering wastewater management facilities. The estimated cost of the project is $1.8 million with an anticipated completion date in the third quarter of 2009.

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 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, to force reductions in carbon dioxide (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 Second Circuit Court of Appeals. In June 2007, the Second Circuit 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 the EPA under the Clean Air Act. In response to the request of the Second Circuit Court of Appeals, in June 2007, 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 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 Fifth Circuit Court of Appeals. The Court of Appeals has taken the matter under advisement and is expected to issue an opinion in due course.

Native Village of Kivalina vs. Xcel Energy Inc. et al. — In February 2008, the City and Native Village of Kivalina, Alaska, filed a lawsuit against Xcel Energy and 23 other 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 carbon dioxide and other greenhouse gases 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. A response to the complaint is due on or before June 30, 2008.

Employment, Tort and Commercial Litigation

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 District Court in Travis County, Texas. In August 2004, the court affirmed the decision of the PUCT. In September 2004, LCEC appealed the District Court’s decision to the Court of Appeals for the Third Supreme Judicial District of the state of Texas. This appeal is currently pending.

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. An adverse ruling on the appeal of May 2003 PUCT order could result in a different determination of the legality of SPS’ service to the disputed customers.

7. Short-Term Borrowings and Other Financing Instruments

Commercial Paper — At March 31, 2008 and Dec. 31, 2007, SPS had commercial paper outstanding of approximately $50.0 million and $123.0 million, respectively. The weighted average interest rates at March 31, 2008 and Dec. 31, 2007 were 3.59 percent and 5.58 percent, respectively.

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 March 31, 2008 and Dec. 31, 2007, SPS had money pool borrowings of $100.0 million and $5.5 million, respectively. The weighted average interest rates at March 31, 2008 and Dec. 31, 2007 were 3.45 percent and 5.64 percent, respectively.

8. Derivative Instruments

SPS uses derivative instruments in connection with its utility commodity price, interest rate, short-term wholesale and commodity trading activities, including forward contracts, futures, swaps and options. Qualifying hedging relationships are

Cash Flow Hedges

Commodity Cash Flow Hedges — SPS enters into derivative instruments to manage variability of future cash flows from changes in commodity prices. These derivative instruments are designated as cash flow hedges for accounting purposes. At March 31, 2008, SPS had no commodity-related contracts designated as cash flow hedges.

Interest Rate Cash Flow Hedges — SPS enters into interest rate swap instruments that effectively fix the interest payments on certain floating rate debt obligations. These derivative instruments are designated as cash flow hedges for accounting purposes.

At March 31, 2008, SPS had net losses of $0.2 million in accumulated other comprehensive income that are expected to be recognized in earnings during the next 12 months.

The following table shows the major components of the derivative instruments valuation in the balance sheets at March 31 and Dec. 31:

	March 31, 2008				Dec. 31, 2007
(Thousands of Dollars)	Derivative Instruments Valuation - Assets		Derivative Instruments Valuation - Liabilities		Derivative Instruments Valuation - Assets		Derivative Instruments Valuation - Liabilities
Long term purchased power agreements	$	92,171	$	58,522	$	94,403	$	59,419
Interest rate hedging instruments	—		7,127		—		5,967
Total	$	92,171	$	65,649	$	94,403	$	65,386

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 the first quarter of 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.

The impact of qualifying cash flow hedges on SPS’ accumulated other comprehensive income, included as a component of common stockholders’ equity, is detailed in the following table:

	Three months ended March 31,
(Thousands of Dollars)	2008			2007
Accumulated other comprehensive loss related to cash flow hedges at Jan. 1	$	(6,005	)	$	(5,860	)
After-tax net unrealized losses related to derivatives accounted for as hedges	(742		)	(8		)
After-tax net realized losses on derivative transactions reclassified into earnings	43			42
Accumulated other comprehensive loss related to cash flow hedges at March 31	$	(6,704	)	$	(5,826	)

9. Fair Value Measurements

Effective Jan. 1, 2008, SPS adopted 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.

SPS had one interest rate derivative contract measured at fair value on a recurring basis as of March 31, 2008. SPS uses broker quotes, based primarily on observable benchmark interest rate forecasts, to measure the fair value of interest rate derivatives. Given the observability of the primary inputs to pricing, the interest rate derivative liability of $7.1 million was assigned a Level 2 under the SFAS No. 157 hierarchy.

10. Detail of Interest and Other Income, Net

Interest and other income, net of nonoperating expenses, for the three months ended March 31 consisted of the following:

	Three months ended March 31,
(Thousands of Dollars)	2008			2007
Interest income	$	826		$	846
Other nonoperating income	47			45
Insurance policy expenses	(10		)	(61		)
Other nonoperating expenses	—			(27		)
Total interest and other income, net	$	863		$	803

11. Segment Information

SPS has one reportable segment. SPS 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 $418.8 million and $365.9 million for the three months ended March 31, 2008 and 2007, respectively.

12. Comprehensive (Loss) Income

The components of total comprehensive (loss) income are shown below:

	Three months ended March 31,
(Thousands of Dollars)	2008			2007
Net (loss) income	$	(1,265	)	$	1,665
Other comprehensive income:
Unrealized gain – marketable securities	—			4
After-tax net unrealized losses related to derivatives accounted for as hedges	(742		)	(9		)
After-tax net realized losses on derivative transactions reclassified into earnings	43			42
Other comprehensive (loss) income	(699		)	37
Comprehensive (loss) income	$	(1,964	)	$	1,702

13. 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 March 31,
	2008 (1)			2007 (1)			2008			2007
(Thousands of Dollars)	Pension Benefits						Postretirement Health Care Benefits
Xcel Energy Inc.
Service cost	$	16,773		$	16,485		$	1,464		$	1,701
Interest cost	40,583			39,598			12,546			13,603
Expected return on plan assets	(68,472		)	(65,891		)	(7,500		)	(7,618		)
Amortization of transition obligation	—			—			3,644			3,611
Amortization of prior service cost (credit)	5,166			6,487			(544		)	(545		)
Amortization of net loss	2,859			3,867			2,718			4,994
Net periodic benefit cost (credit)	(3,091		)	546			12,328			15,746
Credits not recognized due to the effects of regulation	2,592			2,680			—			—
Additional cost recognized due to the effects of regulation	—			—			973			973
Net benefit cost (credit) recognized for financial reporting	$	(499	)	$	3,226		$	13,301		$	16,719
SPS
Net benefit cost (credit) recognized for financial reporting	$	(2,754	)	$	(2,006	)	$	875		$	1,548

(1) Includes qualified and non-qualified pension net periodic benefit cost.

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 and the results of operations set forth in general instructions H (2) (a) of Form 10-Q for wholly owned subsidiaries (reduced disclosure format).

Forward-Looking Information

The following discussion and analysis by management focuses on those factors that had a material effect on the financial condition and results of operations of SPS 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 notes.

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, 2007 and Exhibit 99.01 to this report on Form 10-Q for the quarter ended March 31, 2008.

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, 2007. Commodity price and interest rate risks for SPS are mitigated in most jurisdictions due to cost-based rate regulation. At March 31, 2008, there were no material changes to the financial market risks that affect the quantitative and qualitative disclosures presented as of Dec. 31, 2007.

RESULTS OF OPERATIONS

SPS’ net loss was approximately $1.3 million for the first three months of 2008, compared with net income of approximately $1.7 million for the first three months of 2007.

Electric Utility, Short-term Wholesale and Commodity Trading Margins

Electric fuel and purchased power expenses tend to vary with changing retail and wholesale requirements and unit cost changes in fuel and purchased power. Due to fuel and purchased energy cost recovery mechanisms for customers, most fluctuations in these costs do not materially affect electric utility margin.

SPS has two distinct forms of wholesale sales: short-term wholesale and commodity trading. Short-term wholesale refers to energy related purchase and sales activity and the use of certain financial instruments associated with the fuel required for and energy produced from SPS’ generation assets and energy and capacity purchased to serve native load. Commodity trading is not associated with SPS’ generation assets or the energy and capacity purchased to serve native load.

SPS conducts an inconsequential amount of commodity trading. Margins from commodity trading activity are partially redistributed to Northern States Power Company, a Minnesota corporation, and Public Service Company of Colorado, both wholly owned subsidiaries of Xcel Energy, pursuant to the joint operating agreement (JOA) approved by the FERC. Margins received pursuant to the JOA are reflected as part of base electric utility revenues. Short-term wholesale and commodity trading margins reflect the impact of regulatory sharing, if applicable. Commodity trading revenues are reported net of trading costs (i.e., on a margin basis) in the Statements of Operations. Commodity trading expenses include purchased power, transmission, broker fees and other related costs.

The following table details base electric utility, short-term wholesale and commodity trading activities:

(Millions of Dollars)	Base Electric Utility			Short-Term Wholesale			Commodity Trading			Total
Three months ended March 31, 2008
Electric utility revenues (excluding commodity trading)	$	413		$	6		$	—		$	419
Electric fuel and purchased power	(316		)	(6		)	—			(322		)
Commodity trading revenues	—			—			—			—
Commodity trading expenses	—			—			—			—
Gross margin before operating expenses	$	97		$	—		$	—		$	97
Margin as a percentage of revenues	23.5		%	—		%	—		%	23.2		%

Three months ended March 31, 2007
Electric utility revenues (excluding commodity trading)	$	364		$	3		$	—		$	367
Fuel and purchased power	(261		)	(3		)	—			(264		)
Commodity trading revenues	—			—			—			—
Commodity trading expenses	—			—			(1		)	(1		)
Gross margin before operating expenses	$	103		$	—		$	(1	)	$	102
Margin as a percentage of revenues	28.3		%	—		%	—		%	27.8		%

The following summarizes the components of the changes in base electric revenues and base electric margin for the three months ended March 31:

Base Electric Revenues

(Millions of Dollars)	2008 vs. 2007
Fuel and purchased power cost recovery	$	46
Retail sales growth (excluding weather impact)	4
Firm wholesale	4
SPS potential regulatory settlements	3
Sales mix	(6		)
Estimated impact of weather	(1		)
Other	(1		)
Total increase in base electric revenues	$	49

Base Electric Margin

(Millions of Dollars)	2008 vs. 2007
Retail sales growth (excluding weather impact)	$	4
Firm wholesale	4
SPS potential regulatory settlements	1
Fuel handling and procurement	(6		)
Sales mix	(6		)
Purchased capacity costs	(2		)
Estimated impact of weather	(1		)
Total decrease in base electric margin	$	(6	)

Non-Fuel Operating Expense and Other Costs

Taxes (other than income taxes) - Taxes (other than income taxes) decreased by approximately $1.2 million, or 10.7 percent, for the first three months of 2008, compared with the first three months of 2007. The decrease was primarily due to a reduction in Texas property taxes.

Income taxes - Income tax expense decreased by approximately $1.5 million for the first three months of 2008 compared with the first three months of 2007. The decrease in income tax expense was primarily due to a decrease in pretax income. The effective tax rate was 37.4 percent for the first three months of 2008, compared with 31.1 percent for the same period in 2007. The higher effective tax rate for the first three months of 2008 was primarily due to an increase in the forecasted annual effective tax rate for 2008 as compared to 2007.

Regulation

Summary of Recent Regulatory Developments

The FERC has jurisdiction over rates for electric transmission service in interstate commerce and electricity sold at wholesale, hydro facility licensing, natural gas transportation, accounting practices and certain other activities of SPS. 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, 2007. In addition to the matters discussed below, see Note 5 to the financial statements for a discussion of other regulatory matters.

Other Regulatory Matters

Performance-Based Regulation and Quality of Service Requirements — In Texas, SPS is subject to a quality of service plan requiring SPS to comply with electric service reliability performance targets. In January 2008, the PUCT staff served SPS with notice that it had initiated an investigation to determine whether SPS is in compliance with the Texas Statutes and PUCT rules on reliability and continuity of service. If SPS is found not to be in compliance, the PUCT may initiate an enforcement action and impose administrative penalties up to $25,000 per day.

Lea Power Purchase Power Agreement — Lea Power is a natural gas combined cycle 602MW plant currently being constructed near Hobbs, New Mexico. SPS is expected to start taking energy beginning in the summer of 2008 when Lea Power reaches commercial operations. On April 24, 2008, however, SPS sent Lea Power a notice of default related to its failure to meet two construction milestones. It is uncertain to what extent, if any, this failure will have on Lea Power’s ability

to begin commercial operations in the summer of 2008. The purchase power agreement, which was executed in 2006, provides for SPS to have exclusive rights to dispatch the facility. SPS is currently evaluating the accounting implications of this contract, including capital lease and/or consolidation requirements. Further, restructuring of the contract is being considered. In addition, SPS is also evaluating the three additional purchase power agreements expected to reach commercial operations in the second quarter of 2008.

Item 4. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

SPS maintains a set of disclosure controls and procedures designed to ensure that information required to be disclosed in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission 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 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 the CFO, of the effectiveness of our disclosure controls and the procedures, the CEO and CFO have concluded that SPS’ disclosure controls and procedures are 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. Management, after consultation with legal counsel, has recorded an estimate of the probable cost of settlement or other disposition for such matters. 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 11 and 12 of SPS’ Annual Report on Form 10-K for the year ended Dec. 31, 2007 for a description of certain legal proceedings presently pending.

Item 1A. Risk Factors

SPS’ risk factors are documented in Item 1A of Part I of its 2007 Annual Report on Form 10-K, which is incorporated herein by reference. There have been no material changes to the risk factors.

Item 6. Exhibits

The following Exhibits are filed with this report:

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.

	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

Date: May 5, 2008

	/s/ DAVID L. EVES
	David L. Eves
	President and Chief Executive Officer

Date: May 5, 2008

	/s/ BENJAMIN G.S. FOWKE III
	Benjamin G.S. Fowke III
	Vice President and Chief Financial Officer

Date: May 5, 2008

	/s/ DAVID L. EVES
	David L. Eves
	President and Chief Executive Officer

	/s/ BENJAMIN G.S. FOWKE III
	Benjamin G.S. Fowke III
	Vice President and Chief Financial Officer

	PART I - FINANCIAL INFORMATION

Item l.	Financial Statements
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations
Item 4.	Controls and Procedures

	PART II - OTHER INFORMATION

Item 1.	Legal Proceedings
Item 1A.	Risk Factors
Item 6.	Exhibits
SIGNATURES
Certifications Pursuant to Section 302
Certifications Pursuant to Section 906
Statement Pursuant to Private Litigation