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, 2007

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 or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large Accelerated Filer o Accelerated Filer o Non-Accelerated Filer x

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 April 27, 2007
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 INCOME (UNAUDITED)

(Thousands of Dollars)

	Three Months Ended March 31,
	2007				2006

Operating revenues	$		365,898		$		412,809

Operating expenses
Electric fuel and purchased power	264,407				295,588
Other operating and maintenance expenses	51,093				49,818
Depreciation and amortization	24,688				23,897
Taxes (other than income taxes)	11,562				13,322
Total operating expenses	351,750				382,625

Operating income	14,148				30,184

Interest and other income, net (see Note 8)	803				1,475
Allowance for funds used during construction – equity	—				118

Interest charges and financing costs
Interest charges — including financing costs of $585 and $1,528, respectively	13,034				13,692
Allowance for funds used during construction – debt	(498			)	(681			)
Total interest charges and financing costs	12,536				13,011

Income before income taxes	2,415				18,766
Income taxes	750				6,889
Net income	$	1,665			$	11,877

See Notes to Financial Statements

SOUTHWESTERN PUBLIC SERVICE CO.

STATEMENTS OF CASH FLOWS (UNAUDITED)

(Thousands of Dollars)

	Three Months Ended March 31,
	2007					2006
Operating activities
Net income	$			1,665		$			11,877
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	25,586					25,648
Deferred income taxes	(1,044				)	(4,040				)
Amortization of investment tax credits	(63				)	(63				)
Allowance for equity funds used during construction	—					(118				)
Net realized and unrealized hedging and derivative transactions	66					16
Changes in operating assets and liabilities:
Recoverable electric energy costs	56,253					13,261
Accounts receivable	8,577					36,783
Accrued unbilled revenues	(18,507				)	42,299
Inventories	(1,457				)	(1,111				)
Prepayments and other	986					1,333
Accounts payable	(36,576				)	(32,210				)
Net regulatory assets and liabilities	(1,178				)	(569				)
Other current liabilities	(16,455				)	(7,769				)
Change in other noncurrent assets	(2,063				)	(1,444				)
Change in other noncurrent liabilities	921					1,673
Net cash provided by operating activities	16,711					85,566

Investing activities
Capital/construction expenditures	(29,223				)	(25,696				)
Allowance for equity funds used during construction	—					118
Investments in utility money pool	(42,600				)	—
Repayments from utility money pool	42,600					—
Other investments	309					803
Net cash used in investing activities	(28,914				)	(24,775				)

Financing activities
Proceeds (payments) of short-term debt, net	21,500					(45,915				)
Borrowings under utility money pool arrangement	107,100					500
Repayments under utility money pool arrangement	(97,900				)	(500				)
Dividends paid to parent	(18,581				)	(20,395				)
Net cash provided by (used in) financing activities	12,119					(66,310				)

Net decrease in cash and cash equivalents	(84				)	(5,519				)
Cash and cash equivalents at beginning of period	297					9,407
Cash and cash equivalents at end of period	$			213		$			3,888

Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$		6,793			$		6,645
Cash paid for income taxes (net of refunds received)	3,643					3,067

Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable	$	4,754				$	2,108

See the Notes to Financial Statements

SOUTHWESTERN PUBLIC SERVICE CO.

BALANCE SHEETS (UNAUDITED)

(Thousands of Dollars)

	March 31, 2007					Dec. 31, 2006
ASSETS
Current assets:
Cash and cash equivalents	$			213		$			297
Accounts receivable, net of allowance for bad debts of $2,531 and $2,686, respectively	49,539					56,616
Accounts receivable from affiliates	7,308					8,808
Accrued unbilled revenues	81,312					62,805
Recoverable electric energy costs	26,847					83,100
Materials and supplies inventories	18,991					17,547
Fuel inventories	4,108					4,095
Derivative instruments valuation	8,926					8,926
Prepayments and other	7,418					8,326
Total current assets	204,662					250,520
Property, plant and equipment, at cost:
Electric utility plant	3,422,843					3,401,108
Construction work in progress	62,188					53,051
Total property, plant and equipment	3,485,031					3,454,159
Less accumulated depreciation	(1,485,696				)	(1,462,787				)
Net property, plant and equipment	1,999,335					1,991,372
Other assets:
Prepaid pension asset	108,875					106,193
Regulatory assets	161,912					163,067
Derivative instruments valuation	92,171					94,402
Other investments	5,468					5,846
Other	7,120					7,890
Total other assets	375,546					377,398
Total assets	$			2,579,543		$			2,619,290

LIABILITIES AND EQUITY
Current liabilities:
Short-term debt	$		72,500			$		51,000
Borrowings under utility money pool, weighted average yield of 5.40% at March 31, 2007	9,200					—
Accounts payable	131,486					159,672
Accounts payable to affiliates	8,883					14,783
Accrued interest	17,237					12,099
Dividends payable to parent	17,318					18,581
Taxes accrued	15,957					33,122
Derivative instruments valuation	4,327					4,307
Deferred income taxes	2,660					6,849
Other	20,229					24,944
Total current liabilities	299,797					325,357
Deferred credits and other liabilities:
Deferred income taxes	448,642					451,108
Regulatory liabilities	142,509					143,789
Derivative instruments valuation	63,284					64,187
Pension and employee benefit obligations	54,917					54,647
Asset retirement obligations	4,402					4,341
Deferred investment tax credits	3,153					3,215
Other	9,449					3,329
Total deferred credits and other liabilities	726,356					724,616
Commitments and contingencies (see Note 5)
Capitalization:
Long-term debt	773,935					773,903
Common stock – authorized 200 shares of $1.00 par value, outstanding 100 shares	—					—
Additional paid in capital	478,269					478,269
Retained earnings	307,012					323,008
Accumulated other comprehensive loss	(5,826				)	(5,863				)
Total common stockholder’s equity	779,455					795,414
Total liabilities and equity	$	2,579,543				$	2,619,290

See the Notes to Financial Statements

NOTES TO FINANCIAL STATEMENTS

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, 2007, and Dec. 31, 2006; the results of its operations for the three months ended March 31, 2007 and 2006; and its cash flows for the three months ended March 31, 2007 and 2006. Due to the seasonality of electric sales of SPS, quarterly 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’s Annual Report on Form 10-K for the year ended Dec. 31, 2006 appropriately represent, in all material respects, the current status of the footnotes and are incorporated herein by reference.

Income Taxes — Consistent with prior periods and upon adoption of Financial Accounting Standard Board (FASB) Interpretation No. 48 – “Accounting for Uncertainty in Income Taxes — an interpretation of FASB Statement No. 109”, SPS records interest and penalties related to income taxes as interest charges in the Statements of Income.

Reclassifications — Certain amounts in the Statements of Cash Flows have been reclassified from prior-period presentation to conform to the 2007 presentation. The reclassifications reflect the presentation of unbilled revenues, recoverable purchased electric energy costs and regulatory assets and liabilities as separate items rather than components of other assets and other liabilities within net cash provided by operating activities. In addition, activity related to derivative transactions have been combined into net realized and unrealized hedging and derivative transactions. These reclassifications did not affect total net cash provided by (used in) operating, investing or financing activities within the Statements of Cash Flows.

2. Recently Issued Accounting Pronouncements

Fair Value Measurements (SFAS 157) — In September 2006, the FASB issued Statement of Financial Accounting Standard (SFAS) 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 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 157 is effective for financial statements issued for fiscal years beginning after Nov. 15, 2007. SPS is evaluating the impact of SFAS 157 on its financial condition and results of operations and does not expect the impact of adoption to be material.

The Fair Value Option for Financial Assets and Financial Liabilities - Including an Amendment of FASB Statement No. 115 (SFAS 159) — In February 2007, the FASB issued SFAS 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 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. SPS is evaluating the impact of SFAS 159 on its financial condition and results of operations and does not expect the impact of adoption to be material.

3. Income Taxes

Accounting for Uncertainty in Income Taxes — an interpretation of FASB Statement No. 109 (FIN 48) — In July 2006, the FASB issued FASB Interpretation No. (FIN) 48. FIN 48 prescribes how a company should recognize, measure, present and disclose uncertain tax positions that the company has taken or expects to take in its income tax returns. FIN 48 requires that only income tax benefits that meet the “more likely than not” recognition threshold be recognized or continue to be recognized on its effective date. As required, SPS adopted FIN 48 as of Jan. 1, 2007 and the initial derecognition amounts were reported as a cumulative effect of a change in accounting principle. The cumulative effect of the change, which is reported as an adjustment to the beginning balance of retained earnings, was not material. Following implementation, the ongoing recognition of changes in measurement of uncertain tax positions will be reflected as a component of income tax expense.

SPS is a member of the Xcel Energy affiliated group that files consolidated income tax returns. Xcel Energy has been audited by the Internal Revenue Service (IRS) through tax year 2003, with a limited exception for 2003 research tax credits. The IRS commenced an examination of Xcel Energy’s federal income tax returns for 2004 and 2005 (and research credits for 2003) in the third quarter of 2006, and that examination is anticipated to be complete by March 31, 2008. As of March 31, 2007, the IRS had not proposed any material adjustments. As of March 31, 2007, Xcel Energy’s 2000 through 2002 federal income tax returns remain open under applicable statutes of limitations.

As of March 31, 2007, SPS’s earliest open tax years in which an audit can be initiated by state taxing authorities under applicable statutes of limitations is 2002.

The amount of unrecognized tax benefits was $5.0 million and $5.3 million on Jan. 1, 2007 and March 31, 2007, respectively.

Included in the unrecognized tax benefit balance was $0.2 million and $0.2 million of tax positions on Jan.1, 2007 and March 31, 2007 respectively, which if recognized would affect the annual effective tax rate. In addition the unrecognized tax benefit balance included $4.8 million and $5.1 million of tax positions on Jan. 1, 2007 and March 31, 2007, 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 change in the unrecognized tax benefit balance from Jan. 1, 2007 to March 31, 2007, was due to the addition of similar uncertain tax positions relating to first quarter activity.

SPS’ amount of unrecognized tax benefits could significantly change in the next 12 months as the IRS and state tax audits progress. However, at this time due to the nature of the audit process, it is not reasonably possible to estimate a range of the possible change.

The interest expense liability related to unrecognized tax benefits on Jan. 1, 2007, was not material. The change in the interest expense liability from Jan. 1, 2007, to March 31, 2007, was not material. No amounts were accrued for penalties.

4. Rate Matters

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, wholesale cooperative customers of SPS, filed a rate complaint at the FERC. The complaint alleged that SPS’ rates for wholesale service were excessive and that SPS had incorrectly calculated monthly fuel cost adjustments contained in SPS’ wholesale rate schedules. Among other things, the complainants asserted that SPS was not properly calculating the fuel costs that are eligible for recovery to reflect fuel costs recovered from certain wholesale sales to other utilities, and that SPS had inappropriately allocated average fuel and purchased power costs to other of SPS’ wholesale customers, effectively raising the fuel costs charges to complainants. Cap Rock Energy Corporation (Cap Rock), another full-requirements customer, Public Service Company of New Mexico (PNM) and Occidental Permian Ltd. and Occidental Power Marketing, L.P. (Occidental) intervened in the proceeding.

On May 24, 2006, a FERC administrative law judge (ALJ) issued an initial recommended decision in the proceeding. The FERC will review the initial recommendation and issue a final order. SPS and others have filed exceptions to the ALJ’s initial recommendation. The FERC’s order may or may not follow any of the ALJ’s recommendation. In the recommended decision, 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 allocating incremental fuel costs incurred by SPS in making wholesale sales of system firm capacity and associated energy to other firm customers at market-based rates during this period based on the view that such sales should be treated as opportunity sales.

SPS believes the ALJ erred on significant and material issues that contradict FERC policy or rules of law. Specifically, SPS believes, based on FERC rules and precedent, that it has appropriately applied its FCAC tariff to the proper classes of customers. These market-based sales were of a long-term duration under FERC precedent and were made from SPS’ entire system. Accordingly, SPS believes that the ALJ erred in concluding that these transactions were opportunity sales, which require the assignment of incremental costs.

The FERC has approved system average cost allocation treatment in previous filings by SPS for sales having similar service characteristics and previously accepted for filing certain of the challenged agreements with average fuel cost pricing.

Moreover, SPS believes that the ALJ’s recommendation constituted a violation of the Filed Rate Doctrine in that it effectively results in a retroactive amendment to the SPS FERC-approved FCAC tariff provisions. Under existing regulations, the FERC may modify a previously approved FCAC on a prospective basis. Accordingly, SPS believes it has applied its FCAC correctly and has sought review of the recommended decision by the FERC by filing a brief on the exceptions.

SPS has evaluated all sales made from Jan. 1, 1999 to Dec. 31, 2005. While SPS believes it should ultimately prevail in this proceeding; however, if the FERC were to adopt the majority of the ALJ’s recommendations, SPS’ refund exposure could be approximately $50 million. FERC action is pending. Additionally, SPS has entered into settlement discussions with the wholesale cooperative customers. During the three months ended March 31, 2007, SPS recognized an additional accrual based upon estimates of this potential liability.

Wholesale Power Base Rate Application — On Dec. 1, 2005, SPS filed for a $2.5 million increase in wholesale power rates to certain electric cooperatives. On Jan. 31, 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. The case is presently in the settlement judge procedures and an agreement in principle has been reached for base rates for the full-requirements customers and PNM. One other wholesale customer has not settled. On Sept. 7, 2006, the offer of settlement with respect to the full-requirements customer was filed for approval and on Sept. 19, 2006, the offer of settlement with respect to PNM was filed for approval. Subsequent to filing rebuttal testimony, on March 29, 2007, SPS and the remaining wholesale customer entered into settlement negotiations. The current hearing schedule has been postponed.

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

Texas Retail Base Rate And Fuel Reconciliation Case — On May 31, 2006, SPS filed a Texas retail electric rate case requesting an increase in annual revenues of approximately $48 million, or 6.0 percent. The rate filing was based on a historical test year, an electric rate base of $943 million, a requested return on equity (ROE) of 11.6 percent and a common equity ratio of 51.1 percent.

In addition, SPS submitted a fuel reconciliation filing, which requested approval of approximately $957 million of Texas-jurisdictional fuel and purchased power costs for 2004 through 2005. The combined case was transferred to the Texas Office of Administrative Hearing. As a part of the fuel reconciliation case, fuel and purchased energy costs, which are recovered in Texas through a fixed-fuel and purchased energy recovery factor as a part of SPS’ retail electric rates, were reviewed.

On March 27, 2007, SPS and various intervenors filed a unanimous stipulation agreement related to the Texas retail rate case as well as the fuel reconciliation portion of the proceeding. The agreement includes the following terms:

• The settlement provides for an annual base rate increase of $23 million or approximately 3 percent.

• The settlement is a “black box” agreement, with no stipulated ROE or capital structure.

• The settlement disallows approximately $27 million of SPS’ 2004 and 2005 fuel expense.

• An additional $2.3 million will be deducted from the company’s next fuel reconciliation filing to be made in 2008, associated with the 2006-2007 fuel reconciliation period.

• All of SPS’ existing long-term firm and interruptible capacity wholesale sales will be assigned system average cost for purposes of Texas retail ratemaking, except for sales to El Paso Electric (EPE), which will be determined by the PUCT separately.

• If the PUCT determines incremental fuel cost assignment related to the EPE contract is appropriate, the settlement provides that the fuel disallowance is limited to an annual amount of $6.3 million per year, from the date of the PUCT's order through 2008.

• The settlement also creates standards for cost assignment that would apply to future wholesale sale transactions, and establishes margin sharing of market based wholesale demand revenues.

• If SPS files a general rate case in 2008, the settlement would allow for an interim rate increase associated with a purchased power agreement with Lea Power Partners of approximately $1.5 million per month from the date of commercial operations. Interim rates would be subject to a true up based on the outcome of the rate case proceeding and actual capacity costs incurred.

An estimated settlement allowance and reserve was established in 2006 and prior periods, which approximated the settled amounts of previously deferred or recovered fuel expense; therefore, no additional expense associated with the fuel reconciliation portions of the settlement was recognized in the quarter. On March 27, 2007, the ALJ approved SPS’ request to implement the $23 million base rate increase, effective April 2007, on an interim basis until the PUCT acts on the stipulation. It is expected that the PUCT will consider the settlement at the same time as it considers the EPE wholesale cost assignment, which is likely to occur in the second quarter of 2007.

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

New Mexico Fuel Factor Continuation Filing — On Aug. 18, 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 has been 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 have requested disallowances for past periods, which in the aggregate total approximately $45 million. Other issues in the case include the treatment of renewable energy certificates and sulfur dioxide allowance credit proceeds in relation to SPS’ New Mexico retail fuel and purchased power recovery clause. The hearing was held in April 2006, and the hearing examiner’s recommended decision and a NMPRC decision is expected in the second quarter of 2007. During the three months ended March 31, 2007, SPS recognized an accrual based upon estimates of this potential liability.

5. Commitments and Contingent Liabilities

The circumstances set forth in Note 10 and 11 to the financial statements in SPS’s Annual Report on Form 10-K for the year ended Dec. 31, 2006 and Notes 4 and 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’s 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, 2007, 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.

To estimate the cost to remediate 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, 2007, the liability for the cost of remediating these sites was estimated to be $0.2 million, of which $0.1 million was considered to be a current liability. 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 11 to the SPS Annual Report on Form 10-K for the year ended Dec. 31, 2006. 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.

Cunningham Station Groundwater — Cunningham Station is a natural gas-fired power plant constructed in the 1960’s by SPS and has 28 water wells installed on its water rights. The well field provides water for boiler makeup, cooling water and potable water. Following an acid release in 2002, groundwater samples revealed elevated concentrations of inorganic salt compounds not related to the release. The contamination was identified in wells located near the plant buildings. The source of contamination is thought to be leakage from ponds that receive blow down water from the plant. In response to a request by the New Mexico Environment Department (NMED), SPS prepared a corrective action plan to address the groundwater contamination. Under the plan submitted to the NMED, SPS agreed to control leakage from the plant blow down ponds through construction of a new lined pond, additional irrigation areas to minimize percolation, and installation of additional wells to monitor groundwater quality. On June 23, 2005, NMED issued a letter approving the corrective action plan. The action plan is subject to continued compliance with New Mexico regulations and oversight by the NMED. SPS is evaluating implementation of a similar project at Maddox Station. These actions for Cunningham and Maddox are estimated to cost approximately $4.2 million through 2008 and will be capitalized or expensed as incurred.

Construction and liner installation of the new pond has been completed. A permit application for discharges from the pond has been submitted to the NMED. It is expected that the pond will be ready to be placed into service when the NMED issues Cunningham a permit. The permitting process for Maddox has begun.

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 Minnesota, Texas and Wisconsin, which are within Xcel Energy’s service territory. Xcel Energy generating facilities in other states are not affected. 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.

On July 11, 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 National Ambient Air Quality Standard in any downwind jurisdiction.

On March 15, 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 United States Court of Appeals for the District of Columbia Circuit. Pursuant to the court’s scheduling order, briefing is expected to be finalized in September 2007.

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 following the installation of low NOx burners on Harrington 3 in 2006, additional capital investments, estimated at $23 million, will be remaining for NOx controls in the SPS region. Annual purchases of SO₂ allowances for are estimated in the range of $12 million to $26 million each year, beginning in 2012 for phase I, based on allowance costs and fuel quality as of December 2006.

These cost estimates represent one potential scenario on complying with CAIR, if West Texas is not excluded. There is uncertainty concerning implementation of CAIR. States are required to develop implementation plans within 18 months of the issuance of the new rules and have a significant amount of discretion in the implementation details. Legal challenges to CAIR rules could alter their requirements and/or schedule. The uncertainty associated with the final CAIR rules makes it difficult to project the ultimate amount and timing of capital expenditures and operating expenses.

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. Xcel Energy believes the cost of any required capital investment or allowance purchases will be recoverable from customers.

Clean Air Mercury Rule — In March 2005, the EPA issued the Clean Air Mercury Rule (CAMR), which regulates mercury emissions from power plants for the first time. The EPA’s CAMR uses a national cap-and-trade system, where compliance may be achieved by either adding mercury controls or purchasing allowances or a combination of both and is designed to achieve a 70 percent reduction in mercury emissions. It affects all coal- and oil-fired generating units across the country that are greater than 25 MW. Compliance with this rule occurs in two phases, with the first phase beginning in 2010 and the second phase in 2018. States will be allocated mercury allowances based on coal type and their baseline heat input relative to other states. Each electric generating unit will be allocated mercury allowances based on its percentage of total coal heat input for the state. Similar to CAIR, 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 CAMR, SPS can comply through capital investments in emission controls or purchase of emission “allowances” from other utilities making reductions on their systems. SPS’ preliminary analysis for phase I compliance suggests capital costs of approximately $14.5 million and increased operating and maintenance expenses of approximately $7.9 million, beginning in 2010. Further testing is planned during 2007 to confirm these costs or determine whether different measures will be necessary, which could result in higher costs. Additional costs will be incurred to meet phase II requirements in 2018.

Regional Haze Rules — On June 15, 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 Texas Commission on Environmental Quality 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. Court of Appeals, then these facilities will be subject to BART requirements for NOx, SO₂, and particulate matter (PM). Due to the uncertainties of the litigation outcome, SPS is not able to estimate the cost impact at this time.

Legal Contingencies

In the normal course of business, SPS is party to routine claims and litigation arising from prior and current operations. SPS is actively defending these matters and has recorded a liability related to the probable cost of settlement or other disposition, when it can be reasonably estimated.

Carbon Dioxide Emissions Lawsuit — On July 21, 2004, the attorneys general of eight states and New York City, as well as several environmental groups, filed lawsuits in U.S. District Court for the Southern District of New York against five utilities, including Xcel Energy, to force reductions in carbon dioxide (CO2) emissions. Although SPS is not named as a party to this litigation, the requested relief that Xcel Energy cap and reduce its CO2 emissions could have a material adverse effect on SPS. The other utilities include American Electric Power Co., Southern Co., Cinergy Corp. and Tennessee Valley Authority. CO2 is emitted whenever fossil fuel is combusted, such as in automobiles, industrial operations and coal- or natural gas-fired power plants. 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 four other utility companies filed a motion to dismiss the lawsuit, contending, among other reasons, that the lawsuit is an attempt to usurp the policy-setting role of the U.S. Congress and the president. On Sept. 19, 2005, the judge granted the defendants’ motion to dismiss on constitutional grounds. Plaintiffs filed an appeal to the Second Circuit Court of Appeals. Oral arguments were presented on June 7, 2006 and a decision on the appeal is pending.

Lamb County Electric Cooperative - - On July 24, 1995, Lamb County Electric Cooperative, Inc. (LCEC) petitioned the PUCT for a cease and desist order against SPS alleging that SPS was unlawfully providing service to oil field customers in LCEC’s certificated area. On May 23, 2003, the PUCT issued an order denying LCEC’s petition based on its determination that SPS was granted a certificate in 1976 to serve the disputed customers. LCEC appealed the decision to the District Court in Travis County, Texas and on Aug. 12, 2004, the District Court affirmed the decision of the PUCT. On Sept. 9, 2004, LCEC appealed the District Court’s decision to the Court of Appeals for the Third Supreme Judicial District of the state of Texas, which appeal is currently pending. Oral arguments in the case were heard March 23, 2005. SPS is awaiting the Court of Appeals decision.

On October 18, 1996, LCEC filed a suit for damages against SPS in the District Court in Lamb County, Texas, based on the same facts as alleged in its petition for a cease and desist order at the PUCT. This suit has been dormant since it was filed, awaiting a final determination at the PUCT of the legality of SPS providing electric service to the disputed customers. The PUCT order of May 23, 2003, found that SPS was legally serving the disputed customers thus collaterally determining the issue of liability contrary to LCEC’s position in the suit. An adverse ruling on the appeal of the May 23, 2003 PUCT order could result in a re-determination of the legality of SPS’ service to the disputed customers.

Comer vs. Xcel Energy Inc. et al. — On April 25, 2006, Xcel Energy received notice of a purported class action lawsuit filed in United States District Court for the Southern District of Mississippi. Although SPS is not named as a party to this litigation, if the litigation ultimately results in an unfavorable outcome for Xcel Energy, it could have a material adverse effect on SPS. 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. On July 19, 2006, Xcel Energy filed a motion to dismiss the lawsuit in its entirety.

6. Short-Term Borrowings and Financing Activities

As of March 31, 2007, SPS had $72.5 million of short-term debt outstanding at a weighted average interest rate of 5.39 percent.

7. Derivative Valuation and Financial Impacts

SPS uses a number of different derivative instruments in connection with its utility commodity price, interest rate, and limited short-term wholesale and commodity trading activities, including forward contracts, futures, swaps and options.

All derivative instruments not qualifying for the normal purchases and normal sales exception, as defined by SFAS 133-“Accounting for Derivative Instruments and Hedging Activities,” as amended (SFAS 133), are recorded at fair value. The presentation of these derivative instruments is dependent on the designation of a qualifying hedging relationship. The adjustment to fair value of derivative

instruments not designated in a qualifying hedging relationship are reflected in current earnings or as a regulatory balance. This classification is dependent on the applicability of any regulatory mechanism in place. This includes certain instruments used to mitigate market risk for SPS and all instruments related to the commodity trading operations. The designation of a cash flow hedge permits the classification of fair value to be recorded within Other Comprehensive Income, to the extent effective. The designation of a fair value hedge permits a derivative instrument’s gains or losses to offset the related results of the hedged item in the Statements of Income.

SPS records the fair value of its derivative instruments in its Balance Sheet as separate line items identified as Derivative Instruments Valuation in both current and noncurrent assets and liabilities.

Qualifying hedging relationships are designated as either a hedge of a forecasted transaction or future cash flow (cash flow hedge), or a hedge of a recognized asset, liability or firm commitment (fair value hedge). The types of qualifying hedging transactions that SPS is currently engaged in are discussed below.

Cash Flow Hedges

SPS enters into derivative instruments to manage variability of future cash flows from changes in commodity prices and interest rates. These derivative instruments are designated as cash flow hedges for accounting purposes and changes in the fair value of these instruments are a component of Other Comprehensive Income or deferred as a regulatory asset or liability. This classification is based on the regulatory recovery mechanisms in place. Amounts deferred in these accounts are recorded in earnings as the hedged purchase or sales transaction is settled. This could include the purchase or sale of energy or energy-related products or the use of natural gas to generate electric energy.

As of March 31, 2007, SPS had no commodity-related contracts classified as cash flow hedges.

SPS enters 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 and the change in the fair value of these instruments is recorded as a component of Other Comprehensive Income.

As of March 31, 2007, SPS had net losses of approximately $0.6 million in Accumulated Other Comprehensive Income related to interest rate cash flow hedge contracts that are expected to be recognized in earnings during the next 12 months.

Gains or losses on hedging transactions for the sales of energy or energy-related products are primarily recorded as a component of revenues, hedging transactions for fuel used in energy generation are recorded as a component of fuel costs and interest rate hedging transactions are recorded as a component of interest expense. SPS is allowed to recover in electric rates the costs of certain financial instruments acquired to reduce commodity cost volatility. There was no hedge ineffectiveness in the first quarter of 2007.

The impact of the components of hedges on SPS’ Accumulated Other Comprehensive Income, included as a component of stockholders’ equity, are detailed in the following table:

	Three months ended March 31,
(Millions of dollars)	2007			2006

Accumulated other comprehensive loss related to cash flow hedges at Jan. 1	$	(5.9	)	$	(4.8	)
After-tax net unrealized gains related to derivatives accounted for as hedges	—			0.4
After-tax net realized losses on derivative transactions reclassified into earnings	0.1			—
Accumulated other comprehensive loss related to cash flow hedges at March 31	$	(5.8	)	$	(4.4	)

Derivatives Not Qualifying for Hedge Accounting

SPS has extremely limited commodity trading operations that enter into derivative instruments. These derivative instruments are accounted for on a mark-to-market basis in the Statement of Income. The results of these transactions are recorded as a component of Operating Revenues on the Statement of Income.

SPS may also enter into certain commodity-based derivative transactions, not included in trading operations, which do not qualify for hedge accounting treatment. These derivative instruments are accounted for on a mark-to-market basis in accordance with SFAS 133.

Normal Purchases or Normal Sales Contracts

SPS enters into contracts for the purchase and sale of various commodities for use in its business operations. SFAS 133 requires a company to evaluate these contracts to determine whether the contracts are derivatives. Certain contracts that meet the definition of a derivative may be exempted from SFAS 133 as normal purchases or normal sales. Normal purchases and normal sales are contracts that provide for the purchase or sale of something other than a financial or derivative instrument that will be delivered in quantities expected to be used or sold over a reasonable period in the normal course of business. In addition, normal purchases and normal sales contracts must have a price based on an underlying that is clearly and closely related to the asset being purchased or sold. An underlying is a specified interest rate security price, commodity price, foreign exchange rate, index of prices or rates, or other variable, including the occurrence or nonoccurrence of a specified event, such as a scheduled payment under a contract.

SPS evaluates all of its contracts when such contracts are entered to determine if they are derivatives and, if so, if they qualify and meet the normal designation requirements under SFAS 133. None of the derivative contracts entered into within the commodity trading operations qualify for a normal designation.

Normal purchases and normal sales contracts are accounted for as executory contracts.

8. Detail of Interest and Other Income, Net

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

	Three months ended March 31,
(Thousands of dollars)	2007			2006
Interest income	$	846		$	1,256
Other nonoperating income	45			237
Employee-related insurance policy expense	(61		)	(18		)
Other nonoperating expense	(27		)	—
Total interest and other income, net	$	803		$	1,475

9. 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 $365.9 million and $412.8 million for the three months ended March 31, 2007 and 2006, respectively.

10. Comprehensive Income

The components of total comprehensive income are shown below:

	Three months ended March 31,
(Millions of dollars)	2007		2006
Net income	$	1.7	$	11.9
Other comprehensive income:
After-tax net unrealized gains related to derivatives accounted for as hedges (see Note 7)	—		0.4
After-tax net realized losses on derivative transactions reclassified into earnings (see Note 7)	0.1		—
Other comprehensive income	0.1		0.4
Comprehensive income	$	1.8	$	12.3

The accumulated other comprehensive loss in stockholders’ equity at March 31, 2007 and Dec. 31, 2006 relates to valuation adjustments on SPS’ derivative financial instruments and hedging activities.

11. 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

	Three months ended March 31,
	2007			2006			2007			2006
(Thousands of dollars)	Pension Benefits						Postretirement Health Care Benefits
Xcel Energy Inc.
Service cost	$	16,485		$	16,434		$	1,701		$	1,837
Interest cost	39,598			39,509			13,603			13,183
Expected return on plan assets	(65,891		)	(66,481		)	(7,618		)	(6,268		)
Amortization of transition obligation	—			—			3,611			3,645
Amortization of prior service cost (credit)	6,487			7,427			(545		)	(545		)
Amortization of net loss	3,867			4,511			4,994			6,523
Net periodic benefit cost	546			1,400				15,746			18,375
Credits not recognized due to the effects of regulation	2,680			2,425			—			—
Additional cost recognized due to the effects of regulation	—			—			973			973
Net benefit cost recognized for financial reporting	$	3,226		$	3,825		$	16,719		$	19,348

SPS
Net benefit cost (credit) recognized for financial reporting	$	(2,006	)	$	(1,343	)	$	1,548		$	1,705

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,” “estimate,” “expect,” “objective,” “outlook,” “possible,” “potential” and similar expressions. Actual results may vary materially. Factors that could cause actual results to differ materially include, but are not limited to:

• Economic conditions, including their impact on capital expenditures and the ability of the SPS to obtain financing on favorable terms, inflation rates and monetary fluctuations;

• Business conditions in the energy business;

• Demand for electricity in the nonregulated marketplace;

• Trade, monetary, fiscal, taxation and environmental policies of governments, agencies and similar organizations in geographic areas where SPS has a financial interest;

• Customer business conditions, including demand for their products or services and supply of labor and materials used in creating their products and services;

• Financial or regulatory accounting principles or policies imposed by the Financial Accounting Standards Board, the Securities and Exchange Commission, the Federal Energy Regulatory Commission and similar entities with regulatory oversight;

• Availability or cost of capital such as changes in: interest rates; market perceptions of the utility industry, SPS, Xcel Energy or any of its other subsidiaries; or security ratings;

• Factors affecting utility operations such as unusual weather conditions; catastrophic weather-related damage; unscheduled generation outages, maintenance or repairs; unanticipated changes to fossil fuel or natural gas supply costs or availability due to higher demand, shortages, transportation problems or other developments; environmental incidents; or electric transmission or natural gas pipeline constraints;

• Employee workforce factors, including loss or retirement of key executives, collective bargaining agreements with union employees, or work stoppages;

• Increased competition in the utility industry;

• State and federal legislative and regulatory initiatives that affect cost and investment recovery, have an impact on rate structures and affect the speed and degree to which competition enters the electric markets; industry restructuring initiatives; transmission system operation and/or administration initiatives; recovery of investments made under traditional regulation; nature of competitors entering the industry; retail wheeling; a new pricing structure; and former customers entering the generation market;

• Rate-setting policies or procedures of regulatory entities, including environmental externalities, which are values established by regulators assigning environmental costs to each method of electricity generation when evaluating generation resource options;

• Social attitudes regarding the utility and power industries;

• Cost and other effects of legal and administrative proceedings, settlements, investigations and claims;

• Technological developments that result in competitive disadvantages and create the potential for impairment of existing assets;

• Significant slowdown in growth or decline in the U.S. economy, delay in growth or recovery of the U.S. economy or increased cost for insurance premiums, security and other items;

• Risks associated with implementation of new technologies; and

• Other business or investment considerations that may be disclosed from time to time in SPS’ SEC filings, including “Risk Factors” in Item 1A of SPS’ Annual Report on Form 10-K for the year ended Dec. 31, 2006, or in other publicly disseminated written documents.

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, 2006. Commodity price and interest rate risks for SPS are mitigated in most jurisdictions due to cost-based rate regulation. At March 31, 2007, there were no material changes to the financial market risks that affect the quantitative and qualitative disclosures presented as of Dec. 31, 2006.

RESULTS OF OPERATIONS

SPS’ net income was approximately $1.7 million for the first three months of 2007, compared with approximately $11.9 million for the first three months of 2006.

Electric Utility, Short-term Wholesale and Commodity Trading Margins

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

SPS has two distinct forms of wholesale marketing activities: 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 or realized margins, if applicable. Commodity trading revenues are reported net of trading costs (i.e., on a margin basis) in the Statements of Income. Commodity trading costs include purchased power, transmission, broker fees and other related costs.

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

(Millions of Dollars)	Base Electric Utility			Short-Term Wholesale				Commodity Trading				Consolidated Totals
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 costs	—			—				(1			)	(1				)
Gross margin before operating expenses	$	103		$		—		$		(1	)	$			102
Margin as a percentage of revenues	28.3		%	—			%	—			%	27.8				%

Three months ended March 31, 2006
Electric utility revenues (excluding commodity trading)	$	411		$		2		$		—		$		413
Fuel and purchased power	(294		)	(2			)	—				(296				)
Commodity trading revenues	—			—				—				—
Commodity trading costs	—			—				—				—
Gross margin before operating expenses	$	117		$	—			$	—			$	117
Margin as a percentage of revenues	28.5		%	—			%	—			%	28.3				%

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)	2007 vs. 2006
Fuel cost recovery	$		(56	)
Firm wholesale	4
Transmission revenues	3
Sales growth (excluding weather impact)	1
Estimated impact of weather	1
Total decrease in base electric revenues	$	(47		)

Base Electric Margin

(Millions of dollars)	2007 vs. 2006
SPS potential regulatory settlement	$		(13	)
SPS 2006 favorable fuel recovery	(7			)
Firm wholesale	4
Sales growth (excluding weather impact)	1
Estimated impact of weather	1
Total decrease in base electric margin	$	(14		)

Non-Fuel Operating Expense and Other Costs

Other Operating and Maintenance Expenses - The following summarizes the components of the changes in other operating and maintenance expense for the three months ended March 31:

(Millions of dollars)	2007 vs. 2006
Higher plant outage costs	$		3
Transmission fee classification change	(1			)
Other	(1			)
Total increase in other operating and maintenance expenses	$	1

Taxes (other than income taxes) - Taxes (other than income taxes) decreased by approximately $1.8 million, or 13.2 percent, for the first three months of 2007, compared with the first three months of 2006. The decrease was primarily due to the replacement of the Texas franchise fee with a gross receipts tax.

Interest and other income - Interest and other income decreased by $0.7 million, or 45.6 percent, for the first three months of 2007, compared with the first three months of 2006. The decrease was primarily due to a decrease in the deferred recoverable energy costs interest charges in Texas.

Income taxes - Income taxes decreased by approximately $6.1 million for the first three months of 2007 compared with the first three months of 2006. The effective tax rate was 31.1 percent for the first three months of 2007, compared with 36.7 percent for the same period in 2006. The decreases in income tax expense and the effective tax rate were primarily due to a decrease in pretax income.

Regulation

Summary of Recent Federal Regulatory Developments

The FERC has jurisdiction over rates for electric transmission service in interstate commerce and electric energy sold at wholesale, hydro facility licensing, 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. In addition to the matters discussed below, see Note 4 to the financial statements for a discussion of other regulatory matters.

FERC Rules Implementing Energy Policy Act of 2005 (Energy Act) — The Energy Act repealed the Public Utility Holding Company Act of 1935, effective Feb. 8, 2006. In addition, the Energy Act required the FERC to conduct several rulemakings to adopt new regulations to implement various aspects of the Energy Act. Since Aug. 2005, the FERC has completed or initiated proceedings to modify its regulations on a number of subjects. In addition to the previous disclosure in Item 1 of SPS’ Form 10-K for the year ended Dec. 31, 2006, the FERC issued final rules making certain reliability standards mandatory and subject to potential financial penalties up to $1 million per day per violation for non-compliance effective June 1, 2007.

While SPS cannot predict the ultimate impact the new regulations will have on its operations or financial results, SPS is taking actions that are intended to comply with and implement these new rules and regulations as they become effective.

Electric Transmission Rate Regulation — The FERC also regulates the rates charged and terms and conditions for electric transmission services. FERC policy encourages utilities to turn over the functional control over their electric transmission assets and the related responsibility for the sale of electric transmission services to a Regional Transmission Organization (RTO). SPS is a member of the Southwest Power Pool, Inc. (SPP). Each RTO separately files regional transmission tariff rates for approval by the FERC. All members within that RTO are then subjected to those rates.

On Feb. 15, 2007, the FERC issued final rules adopting revisions to its 1996 open access transmission rules. The final rules are effective May 14, 2007. SPS will be required to complete several compliance actions.

In addition, in January 2007, the FERC issued interim and proposed rules to modify its 2004 standards of conduct rules for electric and natural gas transmission providers, in response to a 2006 court appeal partially vacating the rules. The proposed rules would modify the current FERC rules governing the functional separation of the SPS electric transmission function from the wholesale sales and marketing function. The proposed rules are pending final FERC action.

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 CFO, of the effectiveness of our disclosure controls and procedures, the CEO and CFO have concluded that SPS’ disclosure controls and procedures are effective.

PART I - FINANCIAL INFORMATION
Item l.		Financial Statements (Unaudited)
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

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.

Southwestern Public Service Co.
(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

Date: April 27, 2007

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

Date: April 27, 2007

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

Commission File Number: 001-03789

Environmental Contingencies

Non-Fuel Operating Expense and Other Costs

Part II. OTHER INFORMATION

Item 1. Legal Proceedings

Item 6. Exhibits