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 Sept. 30, 2006

or

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

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

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 Oct. 30, 2006
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 I. FINANCIAL INFORMATION

Item 1. Financial Statements

SOUTHWESTERN PUBLIC SERVICE CO.
STATEMENTS OF INCOME (UNAUDITED)
(Thousands of Dollars)

	Three Months Ended Sept. 30,						Nine Months Ended Sept. 30,
	2006			2005			2006			2005

Operating revenues	$	472,586		$	487,760		$	1,308,575		$	1,181,489

Operating expenses
Electric fuel and purchased power	333,401			346,057			937,694			806,020
Other operating and maintenance expenses	45,585			47,515			144,320			137,033
Depreciation and amortization	23,764			24,910			71,673			72,609
Taxes (other than income taxes)	12,598			13,666			39,972			39,103
Special charges (gains) (Note 6)	(6,076		)	—			(6,076		)	—
Total operating expenses	409,272			432,148			1,187,583			1,054,765

Operating income	63,314			55,612			120,992			126,724

Interest and other income — net (see Note 5)	987			1,643			3,655			5,585
Allowance for funds used during construction — equity	384			746			882			1,718

Interest charges and financing costs
Interest charges — includes financing costs of $1,567, $1,542, $4,669 and $4,578, respectively	13,105			13,432			40,714			40,212
Allowance for funds used during construction — debt	(685		)	(382		)	(2,061		)	(1,392		)
Total interest charges and financing costs	12,420			13,050			38,653			38,820

Income before income taxes	52,265			44,951			86,876			95,207
Income taxes	19,662			16,730			32,405			35,381
Net income	$	32,603		$	28,221		$	54,471		$	59,826

See Notes to Financial Statements

SOUTHWESTERN PUBLIC SERVICE CO.
STATEMENTS OF CASH FLOWS (UNAUDITED)
(Thousands of Dollars)

	Nine Months Ended Sept. 30,
	2006			2005
Operating activities
Net income	$	54,471		$	59,826
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	78,485			78,074
Deferred income taxes	(28,070		)	42,864
Amortization of investment tax credits	(188		)	(188		)
Allowance for equity funds used during construction	(882		)	(1,718		)
Unrealized gain on derivative instruments	(874		)	—
Change in recoverable electric energy costs	44,200			(70,470		)
Change in accounts receivable	35,707			(46,650		)
Change in accrued unbilled revenue	26,561			(17,450		)
Change in inventories	(2,755		)	694
Change in other current assets	959			(263		)
Change in accounts payable	(22,792		)	46,807
Change in other current liabilities	11,482			31,510
Change in other noncurrent assets	(16,164		)	(12,300		)
Change in other noncurrent liabilities	2,673			4,712
Net cash provided by operating activities	182,813			115,448

Investing activities
Capital/construction expenditures	(77,565		)	(89,350		)
Proceeds from sale of OK/KS assets	24,670			—
Allowance for equity funds used during construction	882			1,718
Other investments	16			1,617
Net cash used in investing activities	(51,997		)	(86,015		)

Financing activities
Short-term borrowings — net	(85,000		)	(36,000		)
Borrowings under utility money pool arrangement	324,300			143,700
Repayments under utility money pool arrangement	(324,300		)	(130,100		)
Capital contributions from parent	7,561			56,736
Dividends paid to parent	(59,495		)	(63,769		)
Net cash used in financing activities	(136,934		)	(29,433		)

Net decrease in cash and cash equivalents	(6,118		)	—
Cash and cash equivalents at beginning of year	9,407			5
Cash and cash equivalents at end of quarter	$	3,289		$	5

Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	29,300		$	29,616
Cash paid for income taxes (net of refunds received)	$	45,930		$	(1,698	)

Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable	$	1,525		$	3,701

See Notes to Financial Statements

SOUTHWESTERN PUBLIC SERVICE CO.
BALANCE SHEETS (UNAUDITED)

(Thousands of Dollars)	Sept. 30, 2006			Dec. 31, 2005
ASSETS
Current assets:
Cash and cash equivalents	$	3,289		$	9,407
Accounts receivable — net of allowance for bad debts: $1,678 and $2,658, respectively	72,227			90,049
Accounts receivable from affiliates	3,418			21,303
Accrued unbilled revenues	54,809			81,370
Recoverable electric energy costs	104,150			148,351
Materials and supplies inventories — at average cost	19,400			17,701
Fuel inventory — at average cost	4,094			3,038
Derivative instruments valuation	8,926			22,507
Prepayments and other	6,961			5,920
Total current assets	277,274			399,646
Property, plant and equipment, at cost:
Electric utility plant	3,329,939			3,305,997
Construction work in progress	87,493			69,657
Total property, plant and equipment	3,417,432			3,375,654
Less accumulated depreciation	(1,447,362		)	(1,391,905		)
Net property, plant and equipment	1,970,070			1,983,749
Other assets:
Prepaid pension asset	149,105			143,309
Derivative instruments valuation	96,634			89,642
Regulatory assets	87,827			89,214
Other investments	6,052			8,068
Deferred charges and other	4,576			3,948
Total other assets	344,194			334,181
Total assets	$	2,591,538		$	2,717,576

LIABILITIES AND EQUITY
Current liabilities:
Current portion of long-term debt	$	50,000		$	500,000
Short-term debt	—			85,000
Accounts payable	121,004			148,159
Accounts payable to affiliates	9,890			9,774
Taxes accrued	31,388			27,123
Deferred income taxes	24,483			38,773
Dividends payable to parent	18,486			20,395
Accrued interest	15,203			10,165
Derivative instruments valuation	4,322			26,933
Other	21,435			19,186
Total current liabilities	296,211			885,508
Deferred credits and other liabilities:
Deferred income taxes	453,851			466,415
Regulatory liabilities	143,874			145,931
Derivative instruments valuation	65,148			45,457
Asset retirement obligations	4,361			4,182
Deferred investment tax credits	3,278			3,466
Benefit obligations and other	29,926			26,603
Total deferred credits and other liabilities	700,438			692,054
Commitments and contingencies (see Note 3)
Capitalization:
Long-term debt	776,011			325,776
Common stock — authorized 200 shares of $1.00 par value, outstanding 100 shares	—			—
Additional paid in capital	475,025			467,465
Retained earnings	348,525			351,640
Accumulated other comprehensive loss	(4,672		)	(4,867		)
Total common stockholder’s equity	818,878			814,238
Total liabilities and equity	$	2,591,538		$	2,717,576

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 Sept. 30, 2006, and Dec. 31, 2005; the results of its operations for the three and nine months ended Sept. 30, 2006 and 2005; and its cash flows for the nine months ended Sept. 30, 2006 and 2005. Due to the seasonality of electric sales of SPS, quarterly results are not necessarily an appropriate base from which to project annual results.

Except to the extent updated or described below, the footnotes set forth in the consolidated financial statements in SPS’ Annual Report on Form 10-K for the year ended Dec. 31, 2005 appropriately represent, in all material respects, the current status of the footnotes and are incorporated herein by reference.

1. Significant Accounting Policies

FASB Interpretation No. 48 (FIN 48) — In July 2006, the FASB issued FIN 48, “Accounting for Uncertainty in Income Taxes —an interpretation of FASB Statement No. 109”. FIN 48 prescribes a comprehensive financial statement model of 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 the effective date. Initial derecognition amounts would be reported as a cumulative effect of a change in accounting principle.

FIN 48 is effective for fiscal years beginning after Dec. 15, 2006. SPS is assessing the impact of the new guidance on all of its open tax positions.

Statement of Financial Accounting Standards No. 157 — “Fair Value Measurements” (SFAS No. 157) — In September 2006, the FASB issued SFAS No. 157, which enhances existing guidance for measuring assets and liabilities using fair value. SFAS No. 157 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, not an entity-specific measurement, and sets out a fair value hierarchy with the highest priority being quoted prices in active markets. Under SFAS No. 157, 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. SPS is evaluating the impact of SFAS No. 157 on its financial condition and results of operations.

Statement of Financial Accounting Standards No. 158 — “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans—an amendment of FASB Statements No. 87, 88, 106, and 132(R)” (SFAS No. 158) — In September 2006, the FASB issued SFAS No. 158, which requires companies to fully recognize the funded status of each pension and other postretirement benefit plan as a liability or asset on their balance sheets with all unrecognized amounts to be recorded in other comprehensive income. Although SPS continues to evaluate the impact of the new pronouncement, preliminary estimates indicate that assets could be increased by approximately $32 million and liabilities could be increased by approximately $32 million. SPS is evaluating regulatory accounting treatment, which would allow recognition of this item as a regulatory asset rather than as a charge to other comprehensive income. These estimates reflect the expected deferral of these amounts as regulatory assets or liabilities. The actual impact of the adoption of SFAS No. 158 could differ significantly from this estimate due to plan asset performance for the year and the discount rate in effect at the end of the year when the plans’ liabilities are measured. The implementation of SFAS No.158 will have no impact on net income. SFAS No. 158 is effective as of the end of the fiscal year ending after Dec. 15, 2006.

2. Regulation

FERC Transmission Rate Case — On Sept. 2, 2004, Xcel Energy filed on behalf of SPS and Public Service Company of Colorado (PSCo), an affiliate of SPS, an application to increase wholesale transmission service and ancillary service rates within the Xcel Energy joint open access transmission tariff. PSCo and SPS requested an increase in annual transmission service and ancillary services revenues of $6.1 million. On Feb. 6, 2006, the parties in the proceeding submitted an uncontested offer of settlement. The settlement results in a $1.1 million stated rate increase for SPS effective June 2005, and SPS can file a further rate increase effective Oct. 1, 2006. On April 5, 2006, the Federal Energy Regulatory Commission (FERC) issued an order approving the uncontested settlement.

Most transmission service users of the SPS system take service under the Southwest Power Pool (SPP) regional open access transmission tariff. On May 6, 2006, SPP submitted a compliance filing to the April 5, 2006, FERC order to include the SPS settlement rates in the SPP tariff effective retroactive to June 1, 2005. Certain customer parties protested aspects of the SPP filing as inconsistent with the Feb. 6, 2006 settlement. On Sept. 1, 2006, the FERC issued an order accepting the proposed SPP compliance point-to-point rates, but rejecting the network service tariffs. SPS filed a request for rehearing on Oct. 2, 2006. Separately, SPP filed a revised compliance filing on Oct. 2, 2006, which SPS has protested as inconsistent with the Feb. 6, 2006 settlement. Final FERC action is pending.

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 using the fuel cost adjustment clause (FCAC) provisions 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 FCAC 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. Hearings on the complaint were held in February and March 2006.

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. FERC’s order may or may not follow any of the ALJ’s recommendation.

In the recommended decision, the ALJ resolved a number of disputed cost of service issues and ordered a compliance filing to determine the extent to which base revenues recovered under currently effective rates for the period beginning Jan. 1, 2005, through June 11, 2006 should be refunded to wholesale customers. The ALJ also found that SPS should recalculate its 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. The ALJ failed to acknowledge either factor.

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 rules of law and FERC 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.

Based on FERC regulations and rules of law, SPS has evaluated all sales made from Jan. 1, 1999, to Dec. 31, 2005. While SPS believes it should ultimately prevail in this proceeding, SPS has accrued approximately $7 million, related to both the base-rate and fuel items. However, if the FERC were to adopt the majority of the ALJ’s recommendations, SPS’ refund exposure could be approximately $50 million.

On Sept. 15, 2005, PNM filed a separate complaint at the FERC in which it contended that its demand charge under an existing interruptible power supply contract with SPS is excessive and that SPS has overcharged PNM for fuel costs under three separate agreements through erroneous FCAC calculations. PNM’s arguments were consistent with those that it made as an intervenor in the cooperatives’ complaint case. SPS submitted a response to PNM’s complaint in October 2005. In November 2005, the FERC accepted PNM’s complaint. In July 2006, SPS and PNM reached a settlement in principle and a settlement agreement was filed for approval on Sept. 19, 2006. As a consequence, SPS has accrued approximately $1.3 million to settle all related issues for this complaint.

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, however. On Sept. 7, 2006, the offer of settlement with respect to the full-requirements customers was filed for approval and on Sept. 19, 2006, the offer of settlement with respect to PNM was filed for approval. Hearings have been scheduled for April 2007 for the base rates applicable to the remaining non-settling wholesale customer.

Resource Planning — In June 2006, the New Mexico Public Regulation Commission (NMPRC) initiated a series of workshops for the purpose of drafting rules for integrated resource planning. In August 2006, workshop participants completed a consensus rule that was forwarded by the Hearing Examiner on October 3, 2006, to the NMPRC for consideration. The proposed rules would apply to jurisdictional electric and gas utilities, such as SPS, that operate within the state.

SPP Energy Imbalance Service — On June 15, 2005, SPP, of which SPS is a member, filed proposed tariff provisions to establish an Energy Imbalance Service (EIS) wholesale energy market for the SPP region to be effective March 1, 2006. This market is the first step in a phased approach toward the development of a more comprehensive market, which is expected to eventually include an ancillary services component and perhaps financial transmission rights (FTRs). On Sept. 19, 2005, the FERC issued an order rejecting the SPP EIS proposal and providing guidance and recommendations to SPP; however, the FERC did not require SPP to implement a full Day 2 market similar to MISO. On Jan. 4, 2006, SPP submitted proposed tariff revisions to implement an EIS market and establish a market monitoring and market power mitigation plan. On March 20, 2006, the FERC issued an order conditionally accepting the proposed market, suspending the implementation until Oct. 1, 2006. The FERC found the proposal lacking, particularly with respect to the hiring of an external market monitor, the loss compensation mechanisms and the lack of several standard forms for service. The FERC directed SPP to implement safeguards for the first six months of the imbalance markets including a two tier cap, a market readiness certification and price correction authority. The FERC also ordered balancing authorities to enter into an agreement delineating the respective responsibilities of balancing authorities and SPP in the EIS market.

SPP and market participants engaged in a series of technical conferences to reach agreement on the issue of responsibilities of balancing authorities and SPP in order to comply with the FERC’s order. On May 19, 2006, SPP filed proposed tariff revisions pursuant to the FERC’s January 4th Order. Several parties filed comments and protests to the SPP compliance filing, including SPS. SPP filed an answer to the protests. On July 20, 2006, the FERC accepted in part, and rejected in part, SPP’s proposed market provisions, to become effective on Oct. 1, 2006. On Sept. 26, 2006, the FERC denied requests for rehearing of the March 20, 2006 order. On Oct. 24, 2006, SPP informed FERC that the market would not start on Nov. 1; instead, SPP will evaluate on Dec. 12 a Feb. 1, 2007, market start date. SPS is continuing to participate in pre-operational trials. SPS has concluded that neither NMPRC nor Public Utility Commission of Texas (PUCT) approval is required for SPS to participate in the EIS market.

Texas Energy Legislation — The 2005 Texas Legislature passed a law, effective June 18, 2005, establishing statutory authority for electric utilities outside of the Electric Reliability Council of Texas in the SPP or the Western Electricity Coordinating Council to have timely recovery of transmission infrastructure investments. After notice and hearing, the PUCT may allow recovery on an annual basis of the reasonable and necessary expenditures for transmission infrastructure improvement costs and changes in wholesale transmission charges under a tariff approved by the FERC. The PUCT will initiate a rulemaking for this process that is expected to take place in the second half of 2006.

Fuel Cost Recovery Mechanisms — Fuel and purchased energy costs are recovered in Texas through a fixed-fuel and purchased energy recovery factor, which is part of SPS’ retail electric rates. The Texas retail fuel factors change each November and May based on the projected cost of natural gas. If it appears SPS will materially over-recover or under-recover these costs, the factor may be revised based on application by SPS or action by the PUCT. In 2006, SPS revised its estimate of the allocation of fuel under-recoveries to its Texas jurisdiction for 2004 and 2005 based on a distribution system loss approach. Pursuant to this analysis, the total unrecovered fuel balance is $25.3 million. Because of uncertainty regarding ultimate recovery, a settlement reserve was recorded equal to the entire amount of the unrecovered fuel balance. SPS filed a fuel reconciliation application in May 2006. See further discussion below.

Texas Retail Fuel Factor Change — On Oct. 6, 2006, SPS filed an application to change its fuel factors effective Nov. 1, 2006, to more accurately track fuel cost during the winter months. On Oct. 16, 2006, the PUCT Staff recommended interim approval of the factor changes and on Oct. 16, 2006, the PUCT granted interim approval, effective the first billing cycle of the November 2006 billing month.

Texas Retail Fuel Surcharge Case — On May 5, 2006, SPS requested authority to surcharge approximately $45.5 million of Texas retail fuel and purchased energy cost under-collection that accrued from October 2005 through March 2006. The case was referred to the State Office Of Administrative Hearing (SOAH) for a contested hearing on its merits on Aug. 14, 2006. During the course of this proceeding, certain customers challenged whether a wholesale firm sales contract that SPS has with El Paso Electric Company (EPE) satisfied the terms of a non-unanimous stipulation, dated April 25, 2005, and the PUCT’s final order, dated Dec. 19, 2005, which established the terms under which SPS would be allowed to recover system average fuel cost from certain wholesale firm sales contracts until the issue is addressed in SPS’ base rate case. On Sept. 21, 2006, the PUCT announced its decision that the contract with EPE, which was entered into in July 2004, and prior to the non-unanimous stipulation and final order referred to above and which commenced delivery on Jan. 1, 2006, did not conform to the non-unanimous stipulation and the PUCT’s December 2005 final order and, as a result, disallowed approximately $1.8 million in fuel costs for the period covering October 2005 through March 2006. On Oct. 13, 2006, the PUCT issued a written order confirming its Sept. 21, 2006 rulings, which will control fuel cost recovery for the current EPE contract until a final order in the pending retail rate case discussed below is issued. If the PUCT order stands, a preliminary estimate indicates the disallowance could approximate $8 million for the entire fiscal year, of which approximately $6.4 million has been accrued as of Sept. 30, 2006. SPS will take steps to mitigate the impact of the Sept. 21, 2006 decision. Recovery of the remaining portion of the surcharge of approximately $39 million began on October 1, 2006.

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 is based on a historical test year, an electric rate base of $943 million, a requested return on equity of 11.6 percent and a common equity ratio of 51.1 percent. On Sept. 25, 2006, SPS filed corrections to its rate case revenue requirements calculations increasing the revenue requirements an additional $15 million in annual revenues, to approximately $63 million. The principal revision involves SPS’ jurisdictional allocator and the overstatement of wholesale transmission revenue credits. In order to establish new rates as quickly as possible, SPS does not currently anticipate refiling the entire case. As a result, SPS will be limited to the $48 million increase originally requested. Final rates are now expected to be effective in the second quarter of 2007. No interim rate increase has been implemented. A new procedural schedule in the case has been established and is listed below.

•	Intervenor Testimony	Dec. 15, 2006
•	PUCT Staff Testimony	Jan. 12, 2007
•	SPS Rebuttal Testimony	Jan. 25, 2007
•	Hearings	Jan. 31 through Feb. 23, 2007
•	Decision	May 1, 2007

The fuel reconciliation portion requests approval of approximately $957 million of Texas jurisdictional fuel and purchased power costs for the 2004 through 2005 period. The fuel reconciliation case was transferred to the SOAH with the base rate case and has the same procedural schedule. 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, will be reviewed.

New Mexico Fuel Review — On Jan. 28, 2005, the NMPRC accepted the staff petition for a review of SPS’ fuel and purchased power cost. The staff requested a formal review of SPS’ fuel and purchased power cost adjustment clause (FPPCAC) for the period of Oct. 1, 2001 through August 2004. The hearing in the fuel review case was held April 22, 2006. A proposed recommended decision was filed by the parties on July 28, 2006, and a NMPRC decision is expected in late 2006.

New Mexico Fuel Factor Continuation Filing — On Aug. 18, 2005, SPS filed with the NMPRC requesting continuation of the use of SPS’ 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 ineligible 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 a NMPRC decision is expected in late 2006.

3. Commitments and Contingent Liabilities

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 is pursuing or intends to pursue insurance claims and believes it will recover some portion of these costs through such 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 for such unrecoverable amounts in its Financial Statements.

Clean Air Interstate Rule — In March 2005, the U. S. Environmental Protection Agency (EPA) issued the Clean Air Interstate Rule (CAIR), which further regulates sulfur dioxide (SO2) and nitrogen oxide (NOx) emissions. Under CAIR’s cap-and-trade structure, utilities can comply through capital investments in emission controls or purchase of emission “allowances” from other utilities making reductions on their systems. 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 predict the ultimate amount and timing of capital expenditures and operating expenses.

The Texas Commission on Environmental Quality (TCEQ) adopted the EPA CAIR without further state regulatory requirements. 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 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 CAIR. El Paso Electric Co. joined in the request for reconsideration. 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.

Based on the preliminary analysis of various scenarios of capital investment and allowance purchases, SPS believes the preferred scenario will be capital investments of approximately $30 million for NOx controls with NOx allowance purchases of an estimated $4 million in 2009. Annual purchases of SO2 allowances are estimated in the range of $15 million to $25 million each year, beginning in 2012 for phase I based on allowance costs and fuel quality as of July 2006.

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.

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 TCEQ adopted the CAMR without further state regulatory requirements. SPS continues to evaluate the strategy for complying with CAMR. Compliance may be achieved by either adding mercury controls or purchasing allowances or a combination of both. The capital cost is estimated to be $14.5 million for the mercury control equipment.

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.

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 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.

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’ carbon dioxide 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 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.

Other Contingencies

The circumstances in Note 11 to the financial statements in SPS’s Annual Report on Form 10-K for the year ended Dec. 31, 2005 and Notes 2 and 3 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.

4. Derivative Valuation and Financial Impacts

SPS uses a number of different derivative instruments in connection with its utility operations, limited short-term wholesale and commodity trading activities, including forward contracts, futures, swaps and options. These derivatives instruments are utilized in connection with various commodity prices, certain energy related products, including emission allowances and renewable energy credits, and interest rates. All derivative instruments not qualifying for the normal purchases and normal sales exception, as defined by SFAS No. 133-”Accounting for Derivative Instruments and Hedging Activities,” as amended (SFAS No. 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 specific regulation. 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 Sheets as separate line items identified as Derivative Instruments Valuation in both current and noncurrent assets and liabilities.

The fair value of all interest rate swaps is determined through counterparty valuations, internal valuations and broker quotes. There have been no material changes in the techniques or models used in the valuation of interest rate swaps during the periods presented.

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 in which 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 recorded as 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 Sept. 30, 2006, 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 Sept. 30, 2006, SPS had net losses of approximately $0.2 million in Accumulated Other Comprehensive Loss 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 revenue, 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 third quarter of 2006.

The impact of the components of hedges on SPS’ Accumulated Other Comprehensive Loss, included as a component of stockholder’s equity, is detailed in the following table:

	Nine months ended Sept. 30,
(Millions of dollars)	2006			2005

Accumulated other comprehensive loss related to cash flow hedges at Dec. 31	$	(4.8	)	$	(5.3	)
After-tax net unrealized gains related to derivatives accounted for as hedges	—			0.8
After-tax net realized (gains) losses on derivative transactions reclassified into earnings	0.2			(0.2		)
Accumulated other comprehensive loss related to cash flow hedges at Sept. 30	$	(4.6	)	$	(4.7	)

Fair Value Hedges

The effective portion of the change in the fair value of a derivative instrument qualifying as a fair value hedge is offset against the change in the fair value of the underlying asset, liability or firm commitment being hedged. That is, fair value hedge accounting allows the gains or losses of the derivative instrument to offset, in the same period, the gains and losses of the hedged item.

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 Statements of Income. The results of these transactions are recorded on a net basis within Operating revenues on the Statements 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 No. 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 No. 133 requires a company to evaluate these contracts to determine whether the contracts are derivatives. Certain contracts that literally meet the definition of a derivative may be exempted from SFAS No. 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 No. 133. None of the derivative contracts entered into within the commodity trading operations qualify for a normal designation.

In 2003, as a result of FASB Statement 133 Implementation Issue No. C20, SPS began recording several long-term power purchase 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 will no longer be 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 balances.

Normal purchases and normal sales contracts are accounted for as executory contracts as required under other generally accepted accounting principles.

5. Detail of Interest and Other Income - Net

Interest and other income, net of nonoperating expenses, for the three and nine months ended Sept. 30 consisted of the following:

	Three months ended Sept. 30,						Nine months ended Sept. 30,
(Thousands of dollars)	2006			2005			2006			2005

Interest income	$	936		$	1,745		$	2,888		$	2,457
Other nonoperating income	69			23			895			3,271
Employee-related insurance policy expense	(18		)	—			(128		)	—
Other nonoperating expenses	—			(125		)	—			(143		)
Total interest and other income - net	$	987		$	1,643		$	3,655		$	5,585

6. 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, New Mexico, Kansas and Oklahoma. Revenues from external customers were $472.6 million and $487.8 million for the three months ended Sept. 30, 2006 and 2005. Revenues from external customers were $1,308.6 million and $1,181.5 million for the nine months ended Sept. 30, 2006 and 2005, respectively.

Effective July 31, 2006, SPS completed the sale of its delivery system operations in Oklahoma and Kansas to Tri-County Electric Cooperative for $24.7 million and a gain of $6 million was recognized.

7. Comprehensive Income

The components of total comprehensive income are shown below:

	Three months ended Sept. 30,						Nine months ended Sept. 30,
(Millions of dollars)	2006			2005			2006		2005
Net income	$	32.6		$	28.2		$	54.5	$	59.8
Other comprehensive income:
After-tax net unrealized (gains) losses related to derivatives accounted for as hedges (see Note 5)	(0.6		)	1.0			—		0.8
After-tax net realized losses (gains) on derivative transactions reclassified into earnings (see Note 5)	0.1			(0.1		)	0.2		(0.2		)
Other comprehensive (loss) income	(0.5		)	0.9			0.2		0.6
Comprehensive income	$	32.1		$	29.1		$	54.7	$	60.4

The accumulated other comprehensive loss in stockholder’s equity at Sept. 30, 2006 and Dec. 31, 2005 relates to valuation adjustments on SPS’ derivative financial instruments and hedging activities.

8. 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 Sept. 30,
	2006			2005			2006			2005
(Thousands of dollars)	Pension Benefits						Postretirement Health Care Benefits
Xcel Energy Inc.
Service cost	$	15,406		$	15,115		$	1,659		$	1,671
Interest cost	38,854			40,246			13,234			13,765
Expected return on plan assets	(67,017		)	(70,290		)	(6,690		)	(6,425		)
Amortization of transition obligation	—			—			3,611			3,645
Amortization of prior service cost (credit)	7,424			7,509			(544		)	(545		)
Amortization of net loss	4,339			1,705			6,200			6,562
Net periodic benefit cost (credit)	(994		)	(5,715		)	17,470			18,673
Credits not recognized due to the effects of regulation	3,159			4,842			—			—
Additional cost recognized due to the effects of regulation	—			—			972			972
Net benefit cost (credit) recognized for financial reporting	$	2,165		$	(873	)	$	18,442		$	19,645

SPS
Net benefit cost (credit) recognized for financial reporting	$	(1,734	)	$	(2,276	)	$	1,676		$	1,714

	Nine months ended Sept. 30,
	2006			2005			2006			2005
(Thousands of dollars)	Pension Benefits						Postretirement Health Care Benefits
Xcel Energy Inc.
Service cost	$	46,220		$	45,345		$	4,975		$	5,013
Interest cost	116,560			120,738			39,704			41,295
Expected return on plan assets	(201,049		)	(210,048		)	(20,068		)	(19,275		)
Amortization of transition obligation	—			—			10,833			10,934
Amortization of prior service cost (credit)	22,272			22,527			(1,634		)	(1,634		)
Amortization of net loss	13,015			5,115			18,598			19,685
Net periodic benefit cost (credit)	(2,982		)	(16,323		)	52,408			56,018
Credits not recognized due to the effects of regulation	9,477			14,526			—			—
Additional cost recognized due to the effects of regulation	—			—			2,918			2,918
Net benefit cost (credit) recognized for financial reporting	$	6,495		$	(1,797	)	$	55,326		$	58,936

SPS
Net benefit cost (credit) recognized for financial reporting	$	(5,796	)	$	(6,827	)	$	5,029		$	5,140

9. Subsequent Event

On Oct. 6, 2006, SPS issued $200 million of 10-year senior unsecured notes with a coupon rate of 5.6 percent and $250 million of 30-year senior unsecured notes with a coupon rate of 6 percent. Net proceeds, together with other available funds which may include short-term borrowings, will be used to pay at maturity $500 million of 5.125 percent senior notes due Nov. 1, 2006. Of the $500 million, $450 million was moved from current debt to long-term liabilities.

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

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

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;

• 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, 2005 and Exhibit 99.01 to this report on Form 10-Q for the quarter ended Sept. 30, 2006.

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, 2005. Commodity price and interest rate risks for SPS is mitigated in most jurisdictions due to cost-based rate regulation. At Sept. 30, 2006, there were no material changes to the financial market risks that affect the quantitative and qualitative disclosures presented as of Dec. 31, 2005.

Management Changes

Gary Gibson, president and CEO of SPS, announced his plans to retire on Nov. 30, 2006. Effective July 19, 2006, David Eves was elected CEO by the SPS board of directors. Gary will continue as president of SPS until his retirement.

RESULTS OF OPERATIONS

SPS’ net income was approximately $54.5 million for the first nine months of 2006, compared with approximately $59.8 million for the first nine months of 2005.

Electric Utility, Short-term Wholesale and Commodity Trading Margins

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

Nine months ended Sept. 30, 2006
Electric utility revenue (excluding commodity trading)	$	1,302		$	6		$	—		$	1,308
Electric fuel and purchased power	(932		)	(6		)	—			(938		)
Commodity trading revenue	—			—			1			1
Commodity trading costs	—			—			(1		)	(1		)
Gross margin before operating expenses	$	370		$	—		$	—		$	370
Margin as a percentage of revenue	28.4		%	—		%	—		%	28.3		%

Nine months ended Sept. 30, 2005
Electric utility revenue (excluding commodity trading)	$	1,178		$	3		$	—		$	1,181
Electric fuel and purchased power	(803		)	(3		)	—			(806		)
Commodity trading revenue	—			—			—			—
Commodity trading costs	—			—			—			—
Gross margin before operating expenses	$	375		$	—		$	—		$	375
Margin as a percentage of revenue	31.8		%	—		%	—		%	31.8		%

The following summarizes the components of the changes in base electric revenue and base electric margin for the nine months ended Sept. 30:

Base Electric Revenue

(Millions of dollars)	2006 vs. 2005
Fuel cost recovery	$	123
Sales growth (excluding weather impact)	9
Reserve for potential firm wholesale settlement	(8		)
Texas surcharge rate decision	(6		)
Weather	3
Other	3
Total base electric revenue increase	$	124

Base Electric Margin

(Millions of dollars)	2006 vs. 2005
Sales growth (excluding weather impact)	9
Reserve for potential firm wholesale settlement	$	(8	)
Texas surcharge rate decision	(6		)
Fuel and purchased power recovery	(5		)
Weather	3
Other	2
Total base electric margin decrease	$	(5	)

Non-Fuel Operating Expense and Other Costs

The following summarizes the components of the changes in other utility operating and maintenance expense for the nine months ended Sept. 30:

(Millions of dollars)	2006 vs. 2005
Higher plant maintenance and overhaul costs	$	2
Higher legal arbitration and settlement costs	2
Higher employee benefit costs	4
Other	(1		)
Total other utility operating and maintenance expense increase	$	7

Other income decreased by approximately $2.8 million for the first nine months of 2006, compared with the first nine months of 2005. The decrease was primarily due to a gain on the sale of Amarillo water rights in May of 2005, partially offset by an increase in interest income collected on the Texas deferred fuel balance.

Income taxes decreased by approximately $3.0 million for the first nine months of 2006 compared with the first nine months of 2005. The decrease was primarily due to a decrease in pretax income. The effective tax rate was 37.3 percent for the first nine months of 2006, compared with 37.2 percent for the same period in 2005.

Item 4. CONTROLS AND PROCEDURES

Disclosure Controls

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.

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, its 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 2 and 3 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 is also made to Item 3 of SPS’ Annual Report on Form 10-K for the year ended Dec. 31, 2005 and Note 11of the financial statements in such Form 10-K for a description of certain legal proceedings presently pending. Except as discussed herein in Notes 2 and 3, there are no new significant cases to report against SPS and there have been no notable changes in the previously reported proceedings.

Polychlorinated Biphenyl (PCB) Storage and Disposal — In August 2004, SPS received notice from the EPA contending that SPS violated PCB storage and disposal regulations with respect to storage of a drained transformer and related solids. The EPA contended the fine for the alleged violation was approximately $1.2 million. SPS contested the fine and submitted a voluntary disclosure to the EPA. On April 17, 2006, SPS received a notice of determination from the EPA stating that the voluntary disclosure had been reviewed and that SPS had met all conditions of the EPA’s audit policy. Accordingly, the EPA will mitigate 100 percent of the gravity-based penalty for the disclosed violation, and no economic penalty will be assessed.

Item 1A. RISK FACTORS

SPS’ are documented in Item 1A of Part I of its 2005 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:

	4.01	Fourth Supplemental Indenture, dated October 1, 2006, between Southwestern Public Service Company (a New Mexico corporation) and The Bank of New York, as successor Trustee. (Exhibit 4.01 to SPS Form 8-K (file no. 001-03789) dated October 3, 2006).
	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

	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