SOUTHWESTERN PUBLIC SERVICE CO - FORM 10-K

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EX-23.01 - EXHIBIT 23.01 - SOUTHWESTERN PUBLIC SERVICE CO	ex23_01.htm
EX-31.01 - EXHIBIT 31.01 - SOUTHWESTERN PUBLIC SERVICE CO	ex31_01.htm
EX-32.01 - EXHIBIT 32.01 - SOUTHWESTERN PUBLIC SERVICE CO	ex32_01.htm
EX-31.02 - EXHIBIT 31.02 - SOUTHWESTERN PUBLIC SERVICE CO	ex31_02.htm
EX-12.01 - EXHIBIT 12.01 - SOUTHWESTERN PUBLIC SERVICE CO	ex12_01.htm
EX-99.01 - EXHIBIT 99.01 - SOUTHWESTERN PUBLIC SERVICE CO	ex99_01.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

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

For the fiscal year ended December 31, 2010

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

Commission file number: 001-03789

SOUTHWESTERN PUBLIC SERVICE COMPANY

(Exact name of registrant as specified in its charter)

New Mexico		75-0575400
State or other jurisdiction of incorporation or organization		(I.R.S. Employer Identification No.)

Tyler at Sixth, Amarillo, Texas 79101

(Address of principal executive offices)

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

Securities registered pursuant to Section 12(b) of the Act: None

Securities registered pursuant to section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. o Yes x No

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. o Yes x No

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. x Yes o No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 and Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). o Yes o No

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulations S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

o Large accelerated filer

o Accelerated filer

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

o Smaller Reporting Company

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

As of Feb. 28, 2011, 100 shares of common stock, par value $1 per share, were outstanding, all of which were held by Xcel Energy Inc., a Minnesota corporation.

DOCUMENTS INCORPORATED BY REFERENCE

Xcel Energy Inc.’s Definitive Proxy Statement for its 2011 Annual Meeting of Shareholders is incorporated by reference into Part III of this Form 10-K.

Southwestern Public Service Company meets the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K and is therefore filing this form with the reduced disclosure format permitted by General Instruction I(2).

TABLE OF CONTENTS

Index

PART I	3
Item 1 — Business	3
DEFINITION OF ABBREVIATIONS AND INDUSTRY TERMS	3
COMPANY OVERVIEW	6
ELECTRIC UTILITY OPERATIONS	6
Overview	6
Public Utility Regulation	7
Capacity and Demand	8
Energy Sources and Related Transmission Initiatives	8
Fuel Supply and Costs	9
Fuel Sources	9
Wholesale Commodity Marketing Operations	9
Summary of Recent Federal Regulatory Developments	9
Electric Operating Statistics	11
ENVIRONMENTAL MATTERS	12
EMPLOYEES	12
Item 1A — Risk Factors	12
Item 1B — Unresolved Staff Comments	19
Item 2 — Properties	19
Item 3 — Legal Proceedings	20
Item 4 — Reserved	20

PART II	20
Item 5 — Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	20
Item 6 — Selected Financial Data	20
Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations	21
Item 7A — Quantitative and Qualitative Disclosures About Market Risk	23
Item 8 — Financial Statements and Supplementary Data	23
Item 9 — Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	59
Item 9A — Controls and Procedures	59
Item 9B — Other Information	59

PART III	59
Item 10 — Directors, Executive Officers and Corporate Governance	59
Item 11 — Executive Compensation	59
Item 12 — Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	59
Item 13 — Certain Relationships and Related Transactions, and Director Independence	59
Item 14 — Principal Accountant Fees and Services	59

PART IV	60
Item 15 — Exhibits, Financial Statement Schedules	60

SIGNATURES	63

This Form 10-K is filed by SPS. SPS is a wholly owned subsidiary of Xcel Energy Inc. Additional information on Xcel Energy is available in various filings with the SEC. This report should be read in its entirety.

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PART I

Item l — Business

DEFINITION OF ABBREVIATIONS AND INDUSTRY TERMS

Xcel Energy Subsidiaries and Affiliates
NCE		New Century Energies, Inc.
NSP-Minnesota		Northern States Power Company, a Minnesota corporation
NSP-Wisconsin		Northern States Power Company, a Wisconsin corporation
PSCo		Public Service Company of Colorado, a Colorado corporation
SPS		Southwestern Public Service Company, a New Mexico corporation
utility subsidiaries		NSP-Minnesota, NSP-Wisconsin, PSCo, SPS
Xcel Energy		Xcel Energy Inc., a Minnesota corporation

Federal and State Regulatory Agencies
EIB		New Mexico Environmental Improvement Board
EPA		United States Environmental Protection Agency
FERC		Federal Energy Regulatory Commission. The U.S. agency that regulates the rates and services for transportation of electricity and natural gas; the sale wholesale electricity, in interstate commerce, including the sale of electricity at market-based rates; hydroelectric generation licensing; and accounting requirements for utility holding companies, service companies and public utilities.
IRS		Internal Revenue Service
NERC		North American Electric Reliability Council. A self-regulatory organization, subject to oversight by the FERC and government authorities in Canada, to develop and enforce reliability standards.
NMED		New Mexico Environment Department
NMPRC		New Mexico Public Regulatory Commission. The state agency that regulates the retail rates and services and other aspects of SPS’ operations in New Mexico. The NMPRC also has jurisdiction over the issuance of securities by SPS.
PUCT		Public Utility Commission of Texas. The state agency that regulates the retail rates, services and other aspects of SPS’ operations in Texas.
SEC		Securities and Exchange Commission
TCEQ		Texas Commission on Environmental Quality

Electric and Resource Adjustment Clauses
EECRF		Energy efficiency cost recovery factor
FPPCAC		Fuel and purchased power cost adjustment clause. Allows SPS to use a monthly adjustment factor for fuel and purchased power.
OATT		Open Access Transmission Tariff
TCR		Transmission cost recovery
TCRF		Transmission cost recovery factor

Other Terms and Abbreviations
AFUDC		Allowance for funds used during construction. Defined in regulatory accounts as non-cash accounting convention that represents the estimated composite interest costs of debt and a return on equity funds used to finance construction. The allowance is capitalized in property accounts and included in income.
ALJ		Administrative law judge. A judge presiding over regulatory proceedings.
APBO		Accumulated Postretirement Benefit Obligation
ARO		Asset Retirement Obligation. Obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs.
ASC		FASB Accounting Standards Codification
BAL		Balancing authority
BART		Best Available Retrofit Technology
CAA		Clean Air Act
CAIR		Clean Air Interstate Rule
CAMR		Clean Air Mercury Rule
CATR		Clean Air Transport Rule
CCN		Certificate of Convenience and Necessity

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CIPS	Critical Infrastructure Protection Standards
CO2	Carbon dioxide
Codification	FASB Accounting Standards Codification
CWIP	Construction work in progress
derivative instrument	A financial instrument or other contract with all three of the following characteristics:
	·	An underlying and a notional amount or payment provision or both;
	·	Requires no initial investment or an initial net investment that is smaller than would be required for other types of contracts that would be expected to have a similar response to changes in market factors; and
	·	Terms require or permit a net settlement, can be readily settled net by means outside the contract or provides for delivery of an asset that puts the recipient in a position not substantially different from net settlement.
distribution	The system of lines, transformers, switches, and mains that connect electric transmission systems to customers.
DOI	Department of Investigation
ETR	Effective tax rate
FASB	Financial Accounting Standards Board
GAAP	Generally accepted accounting principles
generation	The process of transforming other forms of energy, such as nuclear or fossil fuels, into electricity. Also, the amount of electric energy produced, expressed in MW (capacity) or MW hours (energy).
GHG	Greenhouse gas
JOA	Joint operating agreement among Xcel Energy’s utility subsidiaries
LIBOR	London Interbank Offered Rate
mark-to-market	The process whereby an asset or liability is recognized at fair value.
MISO	Midwest Independent Transmission System Operator
Moody’s	Moody’s Investor Services
native load	The customer demand of retail and wholesale customers whereby a utility has an obligation to serve: e.g., an obligation to provide electric service created by statute or long-term contract.
NOPR	Notice of proposed rulemaking
NOx	Nitrogen oxide
O&M	Operating and maintenance
OCI	Other comprehensive income
PCB	Polychlorinated biphenyl
PJM	PJM Interconnection, L.L.C.
PPA	Purchased power agreement
PRP	Potentially responsible party
rate base	The investor-owned plant facilities for generation, transmission, and distribution and other assets used in supplying utility service to the consumer.
REC	Renewable energy credit
ROE	Return on equity
ROFR	Right of first refusal
RPS	Renewable Portfolio Standard. A regulation that requires the increased production of energy from renewable energy sources, such as wind, solar, biomass, and geothermal.
RTO	Regional Transmission Organization. An independent entity, which is established to have “functional control” over a utility’s electric transmission systems, in order to provide non-discriminatory access to transmission of electricity.
SO2	Sulfur dioxide
SPP	Southwest Power Pool, Inc.
Standard & Poor’s	Standard & Poor’s Ratings Services
unbilled revenues	Amount of service rendered but not billed at the end of an accounting period. Cycle meter-reading practices result in unbilled consumption between the date of last meter reading and the end of the period.
underlying	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.
wheeling or transmission	An electric service wherein high voltage transmission facilities of one utility system are used to transmit power generated within or purchased from another system.
WTMPA	West Texas Municipal Power Agency

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Measurements
Btu		British thermal unit. A standard unit for measuring thermal energy or heat commonly used as a gauge for the energy content of natural gas and other fuels.
KW		Kilowatts (one KW equals one thousand watts)
KWh		Kilowatt hours
MMBtu		One million Btus
MW		Megawatts (one MW equals one thousand KW)
Volt		The unit of measurement of electromotive force. Equivalent to the force required to produce a current of one ampere through a resistance of one ohm. The unit of measure for electrical potential. Generally measured in kilovolts.
Watt		A measure of power production or usage.

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COMPANY OVERVIEW

SPS was incorporated in 1921 under the laws of New Mexico. SPS is an operating utility engaged primarily in the generation, purchase, transmission, distribution, and sale of electricity in portions of Texas and New Mexico. The wholesale customers served by SPS comprised approximately 36 percent of its total sales in 2010. SPS provides electric utility service to approximately 375,000 retail customers in Texas and New Mexico. Approximately 74 percent of SPS’ retail electric operating revenues were derived from operations in Texas during 2010. Generally, SPS’ earnings contribute approximately 5 percent to 10 percent of Xcel Energy’s consolidated net income.

In October 2010, SPS sold certain electric distribution assets in Lubbock, Texas to Lubbock Power and Light (LP&L) for $87 million. This sale resulted in a pre-tax gain of approximately $20 million which will be shared with retail customers in Texas, and has been deferred as a regulatory liability pending the determination of the sharing by the PUCT. SPS’ retail sales in Lubbock were approximately 3 percent of SPS’ total energy sales in both 2009 and 2010. SPS anticipates it will sell the same amount of power to the city under existing wholesale power arrangements with WTMPA.

SPS focuses on growing through investments in electric rate base to 1) meet growing customer demands, 2) comply with environmental and renewable energy initiatives and 3) maintain or increase reliability and quality of service to customers. SPS files periodic rate cases, establishes formula rate or automatic rate adjustment mechanisms with state and federal regulators to earn a return on its investments and recover costs of operations. Our environmental initiatives are designed to meet customer and policy maker expectations while creating shareholder value.

ELECTRIC UTILITY OPERATIONS

Overview

Environmental Regulations, Climate Change and Clean Energy — Electric utilities are subject to a significant array of environmental regulations. Further, there are significant future environmental regulations under consideration to encourage the use of clean energy technologies and regulate emissions of GHGs to address climate change.

While the regulations, climate change and clean energy continue to evolve, SPS has undertaken a number of initiatives to meet current and prepare for potential future regulations, reduce GHG emissions and respond to state renewable and energy efficiency goals. These initiatives include emission reduction programs, energy efficiency and conservation programs, renewable energy development and technology exploration projects. Although the impact of climate change policy on SPS will depend on the specifics of state and federal policies, legislation and regulation, we believe that, based on prior state commission practice, SPS would be granted the authority to recover the cost of these initiatives through rates.

Utility Competition — The FERC has continued its efforts to promote more competitive wholesale markets through open-access transmission and other means. As a consequence, SPS and its wholesale customers can purchase generation resources from competing wholesale suppliers and use the transmission systems of the utility subsidiaries on a comparable basis to the utility subsidiaries’ to serve their native load.

Transmission — In June 2010, the FERC issued a NOPR that would eliminate any preferential right at the federal level for an incumbent transmission provider to construct new transmission facilities in its service territory (referred to as a ROFR). The NOPR is pending FERC action. Irrespective of the NOPR, the utility subsidiaries are pursuing several new transmission facility projects.

The FERC has approved the open access transmission planning processes for SPP, the RTO serving the SPS System.

In addition to utility-sponsored transmission expansion, several large “overlay” transmission projects have been proposed to construct 765 KV transmission facilities through the service areas of the utility subsidiaries. SPS is participating in certain overlay project evaluations to ensure that any projects proposed are the most cost effective options. It is not certain if or when specific overlay projects may be constructed and placed in service.

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Alternative Energy Options — SPS’ industrial and large commercial customers have the ability to own or operate facilities to generate their own electricity. In addition, customers may have the option of substituting other fuels, such as natural gas or steam or chilled water for heating, cooling, and manufacturing purposes, or the option of relocating their facilities to a lower cost region. While SPS faces these challenges, it believes its rates are competitive with currently available alternatives.

Public Utility Regulation

Summary of Regulatory Agencies and Areas of Jurisdiction — The PUCT and NMPRC regulate SPS’ retail electric operations and have jurisdiction over its retail rates and services and the construction of transmission or generation in their respective states. The municipalities in which SPS operates in Texas have original jurisdiction over SPS’ rates in those communities. Each municipality can deny SPS’ rate increase. SPS can and does then appeal municipal rate decisions to the PUCT, which hears all municipal rate denials in one hearing. The NMPRC also has jurisdiction over the issuance of securities. SPS is regulated by the FERC with respect to its wholesale electric operations, accounting practices, wholesale sales for resale, the transmission of electricity in interstate commerce, compliance with mandatory NERC electric reliability standards and certain natural gas transactions in interstate commerce. SPS has received authorization from the FERC to make wholesale electric sales at market-based prices (see Summary of Recent Federal Regulatory Developments - Market-Based Rate Rules discussion).

Fuel, Purchased Energy and Conservation 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 tariff. The regulations allow retail fuel factors to change up to three times per year.

There is an accounting of over- or under-recovery of fuel and purchased energy expenses under the fixed factor. Regulations also require refunding or surcharging over- or under- recovery amounts, including interest, when they exceed 4 percent of the utility’s annual fuel and purchased energy costs on a rolling 12-month basis, if this condition is expected to continue.

PUCT regulations require periodic examination of SPS fuel and purchased energy costs, the efficiency of the use of fuel and purchased energy, fuel acquisition and management policies and purchased energy commitments. SPS is required to file an application for the PUCT to retrospectively review fuel and purchased energy costs at least every three years.

The NMPRC has authorized SPS to use a monthly adjustment factor for a FPPCAC for SPS’ New Mexico retail jurisdiction. NMPRC regulations require SPS to periodically request authority to continue using its FPPCAC. The NMPRC reviews SPS’ use of its FPPCAC since the filing of its previous fuel clause continuation filing. As a follow-up to SPS’ last rate case, the NMPRC conducted an audit of SPS’ fuel and purchased power costs for a 12-month period from July 2009 through July 2010 and the tracking mechanism to capture costs and revenues associated with SPS’ RECs from assorted wind projects for the 12-month period from July 2009 through July 2010. Audit results are expected in the first quarter of 2011.

SPS recovers fuel and purchased energy costs from its wholesale customers through a monthly wholesale fuel and purchased economic energy cost adjustment clause accepted for filing by the FERC.

Texas EECRF Rider — PUCT regulations established an EECRF rider under which electric utilities may recover costs associated with providing energy efficiency programs. The EECRF rider must be included in a utility’s tariff and may be established in a utility’s base rate case or through a separate request seeking to establish an EECRF. Previously, the PUCT concluded that the rule did not apply to SPS and that energy efficiency costs should be recovered in base rates. As part of the settlement in SPS’ last base rate case, SPS reached a negotiated settlement with the parties and included base rate recovery amounts explicitly designated for energy efficiency. In August 2010, the PUCT adopted a new rule that increases the energy efficiency goals and makes SPS subject to the same requirements with respect to the EECRF as other utilities in the state. Parties can appeal the application of the rule to SPS when SPS files for the rider in the spring of 2011.

Jones CCN — In August 2010, the PUCT approved SPS’ request for a CCN to build a gas-fired combustion turbine generating unit at SPS’ existing Jones Station in Lubbock, Texas with the PUCT. The NMPRC approved a similar CON in December 2010.

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

In July 2010, SPS filed its application to remove disincentives and requested direct lost margin recovery. A final order was received in December 2010 approving $3.3 million for 2010 and 2011. A hearing in this case that focuses on the appropriate long-term mechanism is scheduled for March 2011.

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Solar Contract Approval — In December 2009, SPS entered into five solar energy PPAs with SunEdision, LLC (SunE), for the procurement of solar energy and associated RECs to meet its solar diversity requirements. The SunE PPAs involve five facilities, each consisting of 10 MW of capacity for a term of 20 years. In September 2010, the NMPRC approved the SunE PPAs and SPS’ proposed cost recovery.

New Mexico GHG Regulations — In 2010, the New Mexico EIB adopted regulations to limit and reduce GHGs, including CO2 emissions from power plants and other industrial sources. SPS and several other utilities and industry groups have filed separate appeals with the New Mexico Court of Appeals challenging the validity of these GHG regulations. Compliance costs for these reductions or offsets may increase electricity rates to New Mexico customers. While regulated utilities generally recover costs resulting from regulatory requirements, SPS may not recover all costs related to complying with the regulatory requirements imposed on SPS under the existing EIB regulations. The effect of these regulations on the financial condition of SPS is uncertain, due to the lack of certainty about the validity of these challenged regulations, and also due to the relatively small proportion of SPS total greenhouse gases that are emitted in New Mexico.

TUCO Inc. (TUCO) to Woodward District Extra High Voltage (EHV) Interchange — In June 2009, SPP directed SPS to construct a 178 mile 345 KV transmission line between Lubbock, Texas and Woodward, Okla. The estimated investment in the new line is $149 million and will be recovered from SPP members, including SPS, in accordance with the SPP OATT and the retail ratemaking process. Preliminary work has begun for construction from the TUCO substation to the Oklahoma border. TRC was contracted to do the routing and environmental impact studies. SPS is expected to file an application requesting approval to build the line in March 2011.

Capacity and Demand

Uninterrupted system peak demand for SPS for each of the last three years and the forecast for 2011, assuming normal weather, is listed below.

System Peak Demand (in MW)
2008	2009	2010	2011 Forecast
4,996	5,038	4,985	5,142

The peak demand for the SPS system typically occurs in the summer. The 2010 uninterrupted system peak demand for SPS occurred on Aug. 4, 2010.

Energy Sources and Related Transmission Initiatives

SPS expects to use existing electric generating stations, power purchases and demand side management options to meet its net dependable system capacity requirements.

Purchased Power — SPS has contracts to purchase power from other utilities and independent power producers. Long-term purchase power contracts typically require a periodic payment to secure the capacity from and a charge for the associated energy actually purchased. SPS also makes short-term purchases to comply with minimum availability requirements, and to obtain energy at a lower cost.

SPS Resource Planning

Integrated Resource Planning (IRP) — SPS is soliciting public participation throughout 2011 in its New Mexico 2012 IRP filing through public and webcast meetings. SPS anticipates filing the IRP with the NMPRC in July 2012.

Renewable Energy Portfolio Plan — SPS is required to develop and implement a renewable portfolio plan in which ten percent of its energy to serve its New Mexico retail customers is produced by renewable resources in 2011, increasing to 15 percent in 2015. SPS primarily fulfills its renewable portfolio requirements through the purchase of wind energy. In 2009, the NMPRC granted SPS a variance to allow SPS to delay meeting its solar energy requirement until 2012 provided that SPS compensates for any shortfall of the solar energy requirement for 2011 during 2012 through 2014. SPS executed and received NMPRC approval for a total of 50 MW of photovoltaic solar energy PPAs. SPS requested a variance from the NMPRC to extend the time to implement its other resource diversity requirements to January 2012.

Approved Resource Additions — SPS plans to add a new third gas turbine to its Jones Plant site in Lubbock, Texas. SPS received CCN approvals from the PUCT and NMPRC for the turbine which will become operational in June 2011. This generating unit will add 168 MW of capacity to the SPS service territory. SPS also executed a purchase power agreement with Calpine Energy Services, LP for 200 MW from 2012 through 2018 that was approved by the NMPRC in December 2010.

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Pending Resource Solicitations — SPS finalized a power purchase agreement for 161 MW of wind resources, and requested approval from the NMPRC in December 2010. SPS released a request for proposal in 2009 for approximately 43,000 MWh annually of biomass generation or an equivalent amount of biogas of approximately 326,000 MMBtu annually to meet its other resource diversity requirements in New Mexico. SPS is continuing its efforts to acquire viable biomass generation or a biogas purchase to meet its renewable energy portfolio plan in New Mexico.

Purchased Transmission Services — SPS has contractual arrangements with SPP and regional transmission service providers to deliver power and energy to its native load customers, which are retail and wholesale load obligations with terms of more than one year.

Fuel Supply and Costs

The following table shows the delivered cost per MMBtu of each significant category of fuel consumed for electric generation, the percentage of total fuel requirements represented by each category of fuel and the total weighted average cost of all fuels.

	Coal					Natural Gas					Weighted Average
	Cost		Percent			Cost		Percent			Fuel Cost
2010	$	1.84		71	%	$	4.59		29	%	$	2.64
2009		1.74		73			3.80		27			2.30
2008		1.86		71			8.41		29			3.78

See additional discussion of fuel supply and costs under Item 1A — Risk Factors.

Fuel Sources

Coal — SPS purchases all of its coal requirements for its two coal facilities, Harrington and Tolk electric generating stations, from TUCO. TUCO arranges for the purchase, receiving, transporting, unloading, handling, crushing, weighing, and delivery of coal to meet SPS’ requirements. TUCO is responsible for negotiating and administering contracts with coal suppliers, transporters, and handlers. For the Harrington station, the coal supply contract with TUCO expires in 2016. For the Tolk station, the coal supply contract with TUCO expires in 2017. As of Dec. 31, 2010 and 2009, coal inventories at the Harrington site were approximately 38 and 46 days supply, respectively. As of Dec. 31, 2010 and 2009, coal inventories at the Tolk site were approximately 45 and 54 days supply, respectively. TUCO has coal agreements to supply 90 percent of SPS’ coal requirements in 2011, 57 percent of SPS’ coal requirements in 2012, and 44 percent of SPS’ coal requirements in 2013, which are sufficient quantities to meet the primary needs of the Harrington and Tolk stations.

Natural gas — SPS uses both firm and interruptible natural gas and standby oil in combustion turbines and certain boilers. Natural gas for SPS’ power plants is procured under contracts to provide an adequate supply of fuel; which typically is purchased with terms of one year or less. The transportation and storage contracts expire in various years from 2011 to 2033. All of the natural gas supply contracts have pricing that is tied to various natural gas indices. Most transportation contract pricing is based on FERC and Railroad Commission of Texas approved transportation tariff rates. These transportation rates are subject to revision based upon FERC or Railroad Commission of Texas approval of changes in the timing or amount of allowable cost recovery by providers. Certain natural gas supply and transportation agreements include obligations for the purchase and/or delivery of specified volumes of natural gas or to make payments in lieu of delivery. At Dec. 31, 2010, SPS’ commitments related to supply contracts were approximately $28 million and transportation and storage contracts were approximately $233 million.

Wholesale Commodity Marketing Operations

SPS conducts various wholesale marketing operations, including the purchase and sale of electric capacity, energy and energy related products. SPS uses physical and financial instruments to minimize commodity price and credit risk and hedge supplies and purchases. See additional discussion under Item 7A — Quantitative and Qualitative Disclosures About Market Risk.

Summary of Recent Federal Regulatory Developments

The FERC has jurisdiction over rates for electric transmission service in interstate commerce and electricity sold at wholesale, accounting practices and certain other activities of SPS, and enforcement of NERC mandatory electric reliability standards. 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 11 to the financial statements for a discussion of other regulatory matters.

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FERC Penalty Guidelines Issued — The Energy Act required the FERC to adopt new regulations to implement various aspects of the Energy Act. Violations of FERC rules are potentially subject to enforcement action by the FERC including financial penalties up to $1 million per day per violation.

In September 2010, the FERC issued a policy statement establishing guidelines to determine the financial penalties that would be applied for violations of FERC statutes, rules and orders, including violations of NERC mandatory reliability standard violations investigated by the FERC. The guidelines establish a base violation level for various types of violations, plus mitigating or aggravating factor adders and multipliers, depending on the nature and severity of the violation. Penalties range between a minimal amount and $72.5 million based on an application of a multiplier. The guidelines indicate that the FERC can deviate from the guidelines in its discretion. The guidelines can apply to any investigation where the FERC staff has not begun settlement negotiations regarding an alleged violation.

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

NERC Electric Reliability Standards Compliance

Compliance Audits and Self Reports

In 2008, SPS filed self-reports with SPP, the NERC regional entity for the SPS system, relating to failure to complete certain generation station battery tests, relay maintenance intervals and record keeping associated with certain CIPS. In 2009, SPS reached agreement with SPP that would resolve all open audit findings and self reports by payment of a non-material penalty. SPS reached a settlement agreement with SPP. This settlement agreement has been approved by the NERC and was filed for FERC approval in December 2010. In January 2011, the FERC issued an order accepting the NERC approval with no further action.

In March 2010, SPP conducted a spot check to evaluate compliance with the NERC CIPS. The regional entity issued a non-public final report in August 2010 alleging violations of certain CIPS requirements, including certain violations common to all Xcel Energy utility subsidiaries. Xcel Energy disputes the alleged violations and is working to resolve the issues. To what extent the regional entities or NERC may seek to impose penalties for violations of CIPS is unknown at this time.

In 2010, SPP conducted its triennial audit of SPS compliance with certain NERC mandatory electric reliability standards. The audit did not include an evaluation of SPS compliance with NERC CIPS. The auditors found no standards violations. The written SPP audit report is now being completed.

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

NERC Advisory Regarding Impact of Transmission Field Conditions on Facility Ratings — In October 2010, the NERC issued an advisory requiring utilities to perform an assessment of field versus assumed “as built” transmission infrastructure conditions. In December 2010, the NERC issued a revised advisory extending the period for affected entities to complete their initial assessment and corrective actions until 2013 and 2014, respectively. The advisory compliance cost for SPS is estimated at $11.4 million. SPS will seek recovery through applicable rate-making mechanisms.

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

Proposed Rulemaking on Transmission Planning and Cost Allocation — In June 2010, the FERC issued a NOPR regarding transmission planning and cost allocation. The NOPR would (1) require that local and regional transmission planning processes address public policy requirements established by state or federal laws or regulations; (2) improve coordination between neighboring transmission planning regions of interregional facilities; (3) eliminate any preferential right at the federal level for an incumbent transmission provider to construct new transmission facilities in its service territory, referred to as a ROFR; and (4) require cost allocation methods for transmission facilities to satisfy newly established cost allocation principles. The FERC will consider the written comments provided on the NOPR prior to adopting a final rule. The content of the final rule cannot be predicted at this time; however, limiting an incumbent utility’s preferential ROFR to build transmission in its service territory states may have a negative impact on longer-term growth opportunities for the Xcel Energy utility subsidiaries.

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Market-Based Rate Rules — Each of the Xcel Energy utility subsidiaries was granted market-based rate authority. SPS was reauthorized to sell at market-based rate rules outside its service territory by the FERC in July 2010. Presently, the Xcel Energy utility subsidiaries may not sell power at market-based rates within the SPS balancing authorities, where they have been found to have market power under the FERC’s applicable analysis. SPS has cost-based coordination tariffs that it may use to make sales in its balancing authorities.

FERC Tie Line Investigation — In October 2007, the FERC Office of Enforcement, DOI, commenced a non-public investigation of use of network transmission service arrangements across the Lamar Tie Line, a transmission facility that connects PSCo and SPS. In July 2008, the DOI issued a preliminary report alleging Xcel Energy violated certain FERC policies, rules and approved tariffs, that could result in material penalties under the FERC penalty guidelines. The report does not constitute a finding by the FERC, which may accept, modify or reject any or all of the preliminary conclusions set forth in the report. Xcel Energy provided a response that disagreed with the preliminary report and demonstrated compliance with applicable standards. In December 2010, the DOI initiated settlement negotiations with Xcel Energy regarding possible resolution of the non-public investigation. The final outcome of the FERC DOI investigation and to what extent FERC may seek to impose penalties for violations is unknown at this time.

Electric Operating Statistics

	Year Ended Dec. 31,
	2010			2009			2008
Electric sales (Millions of KWh)
Residential		3,681			3,539			3,505
Commercial and industrial.		14,323			13,981			14,134
Public authorities and other		571			552			555
Total retail		18,575			18,072			18,194
Sales for resale		10,674			10,209			11,453
Total energy sold		29,249			28,281			29,647

Number of customers at end of period
Residential		295,671			313,063			311,345
Commercial and industrial		73,424			77,217			75,734
Public authorities and other		6,134			6,088			5,987
Total retail		375,229			396,368			393,066
Wholesale		39			45			38
Total customers		375,268			396,413			393,104

Electric revenues (Thousands of Dollars)
Residential	$	300,173		$	284,760		$	323,782
Commercial and industrial		733,476			703,300			936,674
Public authorities and other		38,929			34,933			46,434
Total retail.		1,072,578			1,022,993			1,306,890
Wholesale		485,068			408,460			632,332
Other electric revenues		55,344			27,770			53,552
Total electric revenues	$	1,612,990		$	1,459,223		$	1,992,774

KWh sales per retail customer		49,503			45,593			46,287
Revenue per retail customer	$	2,858		$	2,581		$	3,325
Residential revenue per KWh		8.15	¢		8.05	¢		9.24	¢
Commercial and industrial revenue per KWh		5.12			5.03			6.63
Wholesale revenue per KWh		4.54			4.00			5.52

Natural Gas Facilities Used for Electric Generation

SPS does not provide natural gas service at retail, but purchases and transports natural gas for certain of its generation facilities and operates natural gas pipeline facilities connecting the generation facilities to interstate natural gas pipelines. SPS is subject to the jurisdiction of the FERC with respect to certain natural gas transactions in interstate commerce; and to the jurisdiction of the U.S. DOT and the PUCT for pipeline safety compliance.

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ENVIRONMENTAL MATTERS

SPS’ facilities are regulated by federal and state environmental agencies. These agencies have jurisdiction over air emissions, water quality, wastewater discharges, solid wastes and hazardous substances. Various company activities require registrations, permits, licenses, inspections and approvals from these agencies. SPS has received all necessary authorizations for the construction and continued operation of its generation, transmission and distribution systems. SPS’ facilities have been designed and constructed to operate in compliance with applicable environmental standards.

SPS strives to comply with all environmental regulations applicable to its operations. However, it is not possible to determine when or to what extent additional facilities or modifications of existing or planned facilities will be required as a result of changes to environmental regulations, interpretations or enforcement policies or, what effect future laws or regulations may have upon SPS’ operations. For more information on environmental contingencies, see Note 12 to the financial statements.

EMPLOYEES

The number of full-time SPS employees at Dec. 31, 2010 and 2009 was 1,192 and 1,186, respectively. Of these full-time employees, 804, or 67 percent, and 795, or 67 percent, respectively, are covered under collective bargaining agreements which expire in October 2011. Employees of Xcel Energy Services Inc., a subsidiary of Xcel Energy, also provide services to SPS and are not considered in the above amounts.

Item 1A — Risk Factors

Oversight of Risk and Related Processes

The goal of Xcel Energy’s risk management process, which includes SPS, is to understand, manage and, when possible, mitigate material risk; management is responsible for identifying and managing risks, while Xcel Energy’s Board of Directors oversees and holds management accountable. As described more fully below, SPS is faced with a number of different types of risk. We confront legislative and regulatory policy and compliance risks, including risks related to climate change and emission of CO2; risks for recovery of capital and operating costs; resource planning and other long-term planning risks, including resource acquisition risks; financial risks, including credit, interest rate and capital market risks; and macroeconomic risks, including risks related to economic conditions and changes in demand for our products and services. Cross-cutting risks such as these are discussed and managed across business areas and coordinated by Xcel Energy’s and SPS’ senior management. Our risk management process has three parts: identification and analysis, management and mitigation and communication and disclosure.

Our management identifies and analyzes risks to determine materiality and other attributes such as timing, probability and controllability. Management broadly considers our business, the utility industry, the domestic and global economy and the environment to identify risks. Identification and analysis occurs formally through a key risk assessment process conducted by senior management, the securities disclosure process, the hazard risk management process and internal auditing and compliance with financial and operational controls. Management also identifies and analyzes risk through its business planning process and development of goals and key performance indicators, which include risk identification to determine barriers to implementing our strategy. At the same time, the business planning process identifies areas in which there is a potential for a business area to take inappropriate risk to meet goals and determines how to prevent inappropriate risk-taking.

Management seeks to mitigate the risks inherent in the implementation of Xcel Energy’s and SPS’ strategy. The process for risk management and mitigation includes adherence to our code of conduct and other compliance policies, operation of formal risk management structures and groups, and overall business management. At a threshold level, we have developed a robust compliance program and promote a culture of compliance, which mitigates risk. Building on this culture of compliance, we manage and mitigate risks through operation of formal risk management structures and groups, including management councils, risk committees and the services of corporate areas such as internal audit, the corporate controller and legal services. While we have developed a number of formal structures for risk management, many material risks affect the business as a whole and are managed across business areas.

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Management also communicates with Xcel Energy’s Board and key stakeholders regarding risk. Management provides information to Xcel Energy’s Board in presentations and communications over the course of the year. Senior management presents an assessment of key risks to the Board annually. The presentation of the key risks and the discussion provides the Board with information on the risks management believes are material, including the earnings impact, timing, likelihood and controllability. Based on this presentation, the Board reviews risks at an enterprise level and confirms risk management and mitigation are included in Xcel Energy’s and SPS’ strategy. The guidelines on corporate governance and committee charters define the scope of review and inquiry for the Board and committees. The standing committees also oversee risk management as part of their charters. Each committee has responsibility for overseeing aspects of risk and our management and mitigation of the risk. The Xcel Energy Board has overall responsibility for risk oversight. As described above, the Board reviews the key risk assessment process presented by senior management. This key risk assessment analyzes the most likely areas of future risk to Xcel Energy. The Xcel Energy Board also reviews the performance and annual goals of each business area. This review, when combined with the oversight of specific risks by the committees, allows the Board to confirm risk is considered in the development of goals and that risk has been adequately considered and mitigated in the execution of corporate strategy. The presentation of the assessment of key risks also provides the basis for the discussion of risk in our public filings and securities disclosures.

Risks Associated with Our Business

Environmental Risks

We are subject to environmental laws and regulations, with which compliance could be difficult and costly.

We are subject to environmental laws and regulations that affect many aspects of our past, present and future operations, including air emissions, water quality, wastewater discharges and the generation, transport and disposal of solid wastes and hazardous substances. These laws and regulations require us to obtain and comply with a wide variety of environmental registrations, licenses, permits, inspections and other approvals. Environmental laws and regulations can also require us to restrict or limit the output of certain facilities or the use of certain fuels, to install pollution control equipment at our facilities, clean up spills and correct environmental hazards and other contamination. Both public officials and private individuals may seek to enforce the applicable environmental laws and regulations against us. We may be required to pay all or a portion of the cost to remediate (i.e. clean-up) sites where our past activities, or the activities of certain other parties, caused environmental contamination. At Dec. 31, 2010, these sites included third party sites, such as landfills, for which we are alleged to be a potentially responsible party that sent hazardous materials and wastes.

We are also subject to mandates to provide customers with clean energy, renewable energy and energy conservation offerings. These mandates are designed in part to mitigate the potential environmental impacts of utility operations. Failure to meet the requirements of these mandates may result in fines or penalties, which could have a material adverse effect on our results of operations. If our regulators do not allow us to recover all or a part of the cost of capital investment or the O&M costs incurred to comply with the mandates, it could have a material adverse effect on our results of operations.

In addition, existing environmental laws or regulations may be revised, and new laws or regulations seeking to protect the environment may be adopted or become applicable to us, including but not limited to regulation of mercury, NOx, SO2, CO2, particulates and coal ash. We may also incur additional unanticipated obligations or liabilities under existing environmental laws and regulations.

We are subject to physical and financial risks associated with climate change.

There is a growing consensus that emissions of GHGs are linked to global climate change. Climate change creates physical and financial risk. Physical risks from climate change include an increase in sea level and changes in weather conditions, such as changes in precipitation and extreme weather events. We do not serve any coastal communities so the possibility of sea level rises does not directly affect us or our customers.

Our customers’ energy needs vary with weather conditions, primarily temperature and humidity. For residential customers, heating and cooling represent their largest energy use. To the extent weather conditions are affected by climate change, customers’ energy use could increase or decrease depending on the duration and magnitude of the changes.

Increased energy use due to weather changes may require us to invest in more generating assets, transmission and other infrastructure to serve increased load. Decreased energy use due to weather changes may affect our financial condition, through decreased revenues. Extreme weather conditions in general require more system backup, adding to costs, and can contribute to increased system stresses, including service interruptions. Weather conditions outside of our service territory could also have an impact on our revenues. We buy and sell electricity depending upon system needs and market opportunities. Extreme weather conditions creating high energy demand on our own and/or other systems may raise electricity prices as we buy short-term energy to serve our own system, which would increase the cost of energy we provide to our customers.

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Severe weather impacts our service territories, primarily when thunderstorms, tornadoes and snow or ice storms occur. To the extent the frequency of extreme weather events increases, this could increase our cost of providing service. Changes in precipitation resulting in droughts or water shortages could adversely affect our operations, principally our fossil generating units. A negative impact to water supplies due to long-term drought conditions could adversely impact our ability to provide electricity to customers, as well as increase the price they pay for energy. We may not recover all costs related to mitigating these physical and financial risks.

To the extent climate change impacts a region’s economic health, it may also impact our revenues. Our financial performance is tied to the health of the regional economies we serve. The price of energy, as a factor in a region’s cost of living as well as an important input into the cost of goods and services, has an impact on the economic health of our communities. The cost of additional regulatory requirements, such as a tax on GHGs or additional environmental regulation could impact the availability of goods and prices charged by our suppliers which would normally be borne by consumers through higher prices for energy and purchased goods. To the extent financial markets view climate change and emissions of GHGs as a financial risk, this could negatively affect our ability to access capital markets or cause us to receive less than ideal terms and conditions.

Financial Risks

Our profitability depends in part on our ability to recover costs from our customers and there may be changes in circumstances or in the regulatory environment that impair our ability to recover costs from our customers.

We are subject to comprehensive regulation by federal and state utility regulatory agencies. The state utility commissions regulate many aspects of our utility operations, including siting and construction of facilities, customer service and the rates that we can charge customers. The FERC has jurisdiction, among other things, over wholesale rates for electric transmission service and the sale of electric energy in interstate commerce.

Our profitability is dependent on our ability to recover the costs of providing energy and utility services to our customers and earn a return on our capital investment in our utility operations. We currently provide service at rates approved by one or more regulatory commissions. These rates are generally regulated based on an analysis of our costs incurred in a test year. Thus, the rates we are allowed to charge may or may not match our costs at any given time. While rate regulation is premised on providing a reasonable opportunity to earn a reasonable rate of return on invested capital, there can be no assurance that the applicable regulatory commission will judge all of our costs to have been prudently incurred or that the regulatory process in which rates are determined will always result in rates that will produce full recovery of our costs. Rising fuel costs could increase the risk that we will not be able to fully recover our fuel costs from our customers. Furthermore, there could be changes in the regulatory environment that would impair our ability to recover costs historically collected from our customers.

Management currently believes these prudently incurred costs are recoverable given the existing regulatory mechanisms in place. However, changes in regulations or the imposition of additional regulations, including additional environmental regulation or regulation related to climate change, could have an adverse impact on our results of operations and hence could materially and adversely affect our ability to meet our financial obligations, including debt payments.

Any reductions in our credit ratings could increase our financing costs and the cost of maintaining certain contractual relationships.

We cannot be assured that any of our current ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency. In addition, our credit ratings may change as a result of the differing methodologies or change in the methodologies used by the various rating agencies. For example, Standard & Poor’s calculates an imputed debt associated with capacity payments from purchase power contracts. An increase in the overall level of capacity payments would increase the amount of imputed debt, based on Standard & Poor’s methodology. Therefore, our credit ratings could be adversely affected based on the level of capacity payments associated with purchase power contracts or changes in how imputed debt is determined. Any downgrade could lead to higher borrowing costs. Also, we may enter into certain procurement and derivative contracts that require the posting of collateral or settlement of applicable contracts if credit ratings fall below investment grade.

We are subject to capital market and interest rate risks.

Utility operations require significant capital investment in property, plant and equipment; consequently, we are an active participant in debt and equity markets. Any disruption in capital markets could have a material impact on our ability to fund our operations. Capital markets are global in nature and are impacted by numerous issues and events throughout the world economy, such as the recent concerns regarding European sovereign debt. Capital market disruption events, and resulting broad financial market distress, such as the events surrounding the collapse in the U.S. sub-prime mortgage market, could prevent us from issuing new securities or cause us to issue securities with less than ideal terms and conditions, such as higher interest rates.

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Higher interest rates on short-term borrowings with variable interest rates could also have an adverse effect on our operating results. Changes in interest rates may also impact the fair value of the debt securities in the master pension trust, as well as our ability to earn a return on short-term investments of excess cash.

We are subject to credit risks.

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

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

One alternative available to address counterparty credit risk is to transact on liquid commodity exchanges. The credit risk is then socialized through the exchange central clearinghouse function. While exchanges do remove counterparty credit risk, all participants are subject to margin requirements, which create an additional need for liquidity to post margin as exchange positions change value daily. The recently enacted Dodd-Frank Wall Street Reform Act may require broad clearing of financial swap transactions through a central counterparty, which may lead to additional margin requirements that could impact our liquidity. Also, in October 2010, the FERC finalized its rulemaking addressing the credit policies of organized electric markets, such as SPP, which may lead to additional margin requirements that could impact our liquidity.

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

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

Increasing costs associated with our defined benefit retirement plans and other employee benefits may adversely affect our results of operations, financial position, or liquidity.

We have defined benefit pension and postretirement plans that cover substantially all of our employees. Assumptions related to future costs, return on investments, interest rates and other actuarial assumptions have a significant impact on our funding requirements related to these plans. These estimates and assumptions may change based on economic conditions, actual stock market performance, changes in interest rates and changes in governmental regulations. In addition, the Pension Protection Act of 2006 changed the minimum funding requirements for defined benefit pension plans beginning in 2008. Therefore, our funding requirements and related contributions may change in the future. Also, the payout of a significant percentage of pension plan liabilities in a single year due to high retirements or employees leaving the company would trigger settlement accounting and could require the company to recognize material incremental pension expense related to unrecognized plan losses in the year these liabilities are paid.

Increasing costs associated with health care plans may adversely affect our results of operations.

Our self-insured costs of health care benefits for eligible employees and costs for retiree health care plans have increased substantially in recent years. Increasing levels of large individual health care claims and overall health care claims could have an adverse impact on our operating results, financial position and liquidity. We believe that our employee benefit costs, including costs related to health care plans for our employees and former employees, will continue to rise. Legislation related to health care could also significantly change our benefit programs and costs.

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Operational Risks

We are subject to commodity risks and other risks associated with energy markets and energy production.

We engage in wholesale sales and purchases of electric capacity, energy, and energy-related products and are subject to market supply and commodity price risk. Commodity price changes can affect the value of our commodity trading derivatives. We mark certain derivatives to estimated fair market value on a daily basis (mark-to-market accounting), which may cause earnings volatility. Actual settlements can vary significantly from these estimates, and significant changes from the assumptions underlying our fair value estimates could cause significant earnings variability.

If we encounter market supply shortages or our suppliers are otherwise unable to meet their contractual obligations, we may be unable to fulfill our contractual obligations to our retail, wholesale and other customers at previously authorized or anticipated costs. Any such disruption, if significant, could cause us to seek alternative supply services at potentially higher costs or suffer increased liability for unfulfilled contractual obligations. Any significantly higher energy or fuel costs relative to corresponding sales commitments would have a negative impact on our cash flows and could potentially result in economic losses. Potential market supply shortages may not be fully resolved through alternative supply sources and such interruptions may cause short-term disruptions in our ability to provide electric services to our customers. The impact of these cost and reliability issues depends on our operating conditions such as generation fuels mix, availability of water for cooling, availability of fuel transportation, electric generation capacity, transmission, etc.

Our utility operations are subject to long-term planning risks.

On a periodic basis, or as needed, our utility operations file long-term resource plans with our regulators. These plans are based on numerous assumptions over the relevant planning horizon such as: sales growth, economic activity, costs, regulatory mechanisms, impact of technology on sales and production, customer response and continuation of the existing utility business model. Given the uncertainty in these planning assumptions, there is a risk that the magnitude and timing of resource additions and demand may not coincide. This could lead to under recovery of costs or insufficient resources to meet customer demand.

As we are a subsidiary of Xcel Energy, we may be negatively affected by events impacting the credit or liquidity of Xcel Energy and its affiliates.

If Xcel Energy were to become obligated to make payments under various guarantees and bond indemnities or to fund its other contingent liabilities, or if either Standard & Poor’s or Moody’s were to downgrade Xcel Energy’s credit rating below investment grade, Xcel Energy may be required to provide credit enhancements in the form of cash collateral, letters of credit or other security to satisfy part or potentially all of these exposures. If either Standard & Poor’s or Moody’s were to downgrade Xcel Energy’s debt securities below investment grade, it would increase Xcel Energy’s cost of capital and restrict its access to the capital markets. This could limit Xcel Energy’s ability to contribute equity or make loans to us, or may cause Xcel Energy to seek additional or accelerated funding from us in the form of dividends. If such event were to occur, we may need to seek alternative sources of funds to meet our cash needs.

As of Dec. 31, 2010, Xcel Energy had approximately $9.3 billion of long-term debt and $0.5 billion of short-term debt and current maturities. Xcel Energy provides various guarantees and bond indemnities supporting some of its subsidiaries by guaranteeing the payment or performance by these subsidiaries for specified agreements or transactions.

Xcel Energy also has other contingent liabilities resulting from various tax disputes and other matters. Xcel Energy’s exposure under the guarantees is based upon the net liability of the relevant subsidiary under the specified agreements or transactions. The majority of Xcel Energy’s guarantees limit its exposure to a maximum amount that is stated in the guarantees. As of Dec. 31, 2010, Xcel Energy had guarantees outstanding with a maximum stated amount of approximately $155.7 million and $18.0 million of exposure. Xcel Energy also had additional guarantees of $32.5 million at Dec. 31, 2010 for performance and payment of surety bonds for the benefit of itself and its subsidiaries, with total exposure that cannot be estimated at this time. If Xcel Energy were to become obligated to make payments under these guarantees and bond indemnities or become obligated to fund other contingent liabilities, it could limit Xcel Energy’s ability to contribute equity or make loans to us, or may cause Xcel Energy to seek additional or accelerated funding from us in the form of dividends. If such event were to occur, we may need to seek alternative sources of funds to meet our cash needs.

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We are a wholly owned subsidiary of Xcel Energy. Xcel Energy can exercise substantial control over our dividend policy and business and operations and may exercise that control in a manner that may be perceived to be adverse to our interests.

All of the members of our board of directors, as well as many of our executive officers, are officers of Xcel Energy. Our board makes determinations with respect to a number of significant corporate events, including the payment of our dividends.

We have historically paid quarterly dividends to Xcel Energy. In 2010, 2009 and 2008 we paid $67.1 million, $66.8 million and $61.8 million of dividends to Xcel Energy, respectively. If Xcel Energy’s cash requirements increase, our board of directors could decide to increase the dividends we pay to Xcel Energy to help support Xcel Energy’s cash needs. This could adversely affect our liquidity.

Public Policy Risks

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

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

The EPA has taken steps to regulate GHGs under the CAA. In December 2009, the EPA issued a finding that GHG emissions endanger public health and welfare, and that motor vehicle emissions contribute to the GHGs in the atmosphere. This endangerment finding created a mandatory duty for the EPA to regulate GHGs from light duty motor vehicles. In January 2011, new EPA permitting requirements became effective for GHG emissions of new and modified large stationary sources, which are applicable to construction of new power plants or power plant modifications that increase emissions above a certain threshold. The EPA has also announced that it will propose GHG regulations applicable to emissions from existing power plants in July 2011, with final standards to be issued in 2012.

We are also currently a party to climate change lawsuits and may be subject to additional climate change lawsuits, including lawsuits similar to those described in Note 12 to the financial statements. While we believe such lawsuits are without merit, an adverse outcome in any of these cases could require substantial capital expenditures that cannot be determined at this time and could possibly require payment of substantial penalties or damages. Defense costs associated with such litigation can also be significant. Such payments or expenditures could affect results of operations, cash flows, and financial condition if such costs are not recovered through regulated rates.

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

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

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Increased risks of regulatory penalties could negatively impact our business.

The Energy Act increased the FERC’s civil penalty authority for violation of FERC statutes, rules and orders. The FERC can now impose penalties of $1 million per violation per day. In addition, more than 120 electric reliability standards that were historically subject to voluntary compliance are now mandatory and subject to potential financial penalties by NERC or FERC for violations. If a serious reliability incident did occur, it could have a material adverse effect on our operations or financial results.

Macroeconomic Risks

Economic conditions could negatively impact our business.

Our operations are affected by local, national and worldwide economic conditions. The consequences of a prolonged economic recession and uncertainty of recovery may result in a sustained lower level of economic activity and uncertainty with respect to energy prices and the capital and commodity markets. A sustained lower level of economic activity may also result in a decline in energy consumption, which may adversely affect our revenues and future growth. Instability in the financial markets, as a result of recession or otherwise, also may affect the cost of capital and our ability to raise capital, which are discussed in greater detail in the capital market risk section above.

Current economic conditions may be exacerbated by insufficient financial sector liquidity leading to potential increased unemployment, which may impact customers’ ability to pay timely, increase customer bankruptcies, and may lead to increased bad debt.

Further, worldwide economic activity has an impact on the demand for basic commodities needed for utility infrastructure, such as steel, copper, aluminum, etc., which may impact our ability to acquire sufficient supplies. Additionally, the cost of those commodities may be higher than expected.

Our operations could be impacted by war, acts of terrorism, threats of terrorism or disruptions in normal operating conditions due to localized or regional events.

Our generation plants, fuel storage facilities, transmission and distribution facilities and information systems may be targets of terrorist activities that could disrupt our ability to produce or distribute some portion of our energy products. Any such disruption could result in a significant decrease in revenues and significant additional costs to repair and insure our assets, which could have a material adverse impact on our financial condition and results of operations. The potential for terrorism has subjected our operations to increased risks and could have a material adverse effect on our business. While we have already incurred increased costs for security and capital expenditures in response to these risks, we may experience additional capital and operating costs to implement security for our plants, such as additional physical plant security and additional security personnel. We have also already incurred increased costs for compliance with NERC reliability standards associated with critical infrastructure protection, and may experience additional capital and operating costs to comply with the NERC critical infrastructure protection standards as they are implemented and clarified.

The insurance industry has also been affected by these events and the availability of insurance covering risks we and our competitors typically insure against may decrease. In addition, the insurance we are able to obtain may have higher deductibles, higher premiums and more restrictive policy terms. For example, wildfire events, particularly in the geographic areas we serve, may cause insurance for wildfire losses to become difficult or expensive to obtain.

A security breach of our information systems could impact the reliability of our generation, transmission and distribution systems and also subject us to financial harm associated with theft or inappropriate release of certain types of information, including, but not limited to system operating information and information regarding our customers and employees. We are unable to quantify the potential impact of such an event, however, such an event could result in significant costs and penalties as well as legal costs.

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A disruption of the regional electric transmission grid, interstate natural gas pipeline infrastructure or other fuel sources, could negatively impact our business. Because our generation and transmission systems are part of an interconnected system, we face the risk of possible loss of business due to a disruption caused by the actions of a neighboring utility or an event (severe storm, severe temperature extremes, generator or transmission facility outage, pipeline rupture, railroad disruption, or any disruption of work force such as may be caused by flu epidemic) within our operating systems or on a neighboring system. Any such disruption could result in a significant decrease in revenues and significant additional costs to repair assets, which could have a material adverse impact on our financial condition and results.

The degree to which we are able to maintain day-to-day operations in response to unforeseen events, potentially through the execution of our business continuity plans, will in part determine the financial impact of certain events on our financial condition and results. It’s difficult to predict the magnitude of such events and associated impacts.

Rising energy prices could negatively impact our business.

Higher fuel costs could significantly impact our results of operations if requests for recovery are unsuccessful. In addition, higher fuel costs could reduce customer demand and/or increase bad debt expense, which could also have a material impact on our results of operations. Delays in the timing of the collection of fuel cost recoveries as compared with expenditures for fuel purchases could have an impact on our cash flows. We are unable to predict future prices or the ultimate impact of such prices on our results of operations or cash flows.

Our operating results may fluctuate on a seasonal and quarterly basis and can be adversely affected by milder weather.

Our electric utility business is seasonal, and weather patterns can have a material impact on our operating performance. Demand for electricity is often greater in the summer and winter months associated with cooling and heating. Accordingly, our operations have historically generated less revenues and income when weather conditions are milder in the winter and cooler in the summer. Unusually mild winters and summers could have an adverse effect on our financial condition and results of operations.

Item 1B — Unresolved Staff Comments

None.

Item 2 — Properties

Electric Utility Generating Stations:

SPS			Summer 2010
			Net Dependable
Station, Location and Unit	Fuel	Installed	Capability (MW)
Steam:
Harrington-Amarillo, Texas, 3 Units	Coal	1976-1980	1,018
Tolk-Muleshoe, Texas, 2 Units	Coal	1982-1985	1,065
Cunningham-Hobbs, N.M., 2 Units	Natural Gas	1957-1965	257
Jones-Lubbock, Texas, 2 Units	Natural Gas	1971-1974	486
Maddox-Hobbs, N.M.	Natural Gas	1967	118
Moore County-Amarillo, Texas	Natural Gas	1954	46
Nichols-Amarillo, Texas, 3 Units	Natural Gas	1960-1968	457
Plant X-Earth, Texas, 4 Units	Natural Gas	1952-1964	412
Combustion Turbine:
Carlsbad-Carlsbad, N.M.	Natural Gas	1968	10
Cunningham-Hobbs, N.M., 2 Units	Natural Gas	1998	223
Maddox-Hobbs, N.M.	Natural Gas	1963-1976	58
Riverview-Electric City, Texas	Natural Gas	1973	22
Diesel:
Tucumcari-Tucumcari, N.M., 2 Units	Diesel	1976-1979	-	(a)
		Total	4,172

(a)	This capacity is only available in emergency situations. Therefore, the on-demand net dependable capacity is zero.

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Electric utility overhead and underground transmission and distribution lines (measured in conductor miles) at Dec. 31, 2010:

Conductor Miles
345 KV			6,806
230 KV			9,509
115 KV			11,365
Less than 115 KV			21,130

SPS had 421 electric utility transmission and distribution substations at Dec. 31, 2010.

Item 3 — Legal Proceedings

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

Additional Information

For a discussion of legal claims and environmental proceedings, see Note 12 to the financial statements. For a discussion of proceedings involving utility rates and other regulatory matters, see Item 1 for Public Utility Regulation, Summary of Recent Federal Regulatory Developments and Note 11 to the financial statements for further discussion.

Item 4 — Reserved

PART II

Item 5 — Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

SPS is a wholly owned subsidiary and there is no market for its common equity securities.

SPS has dividend restrictions imposed by its credit facility, FERC rules and state regulatory commissions.

·	SPS’ credit facility includes a financial covenant that requires the equity-to-total capitalization ratio to be greater than or equal to 35 percent. SPS was in compliance as its equity-to-total capitalization ratio was 50 percent and 51 percent at Dec. 31, 2010 and 2009, respectively.

·	Dividends are subject to the FERC’s jurisdiction under the Federal Power Act, which prohibits the payment of dividends out of capital accounts; payment of dividends is allowed out of retained earnings only.

·	State regulatory commissions indirectly limit the amount of dividends that SPS can pay Xcel Energy.

The dividends declared during 2010 and 2009 were as follows:

(Thousands of Dollars)	2010		2009
First quarter	$	16,896	$	17,374
Second quarter		16,674		16,854
Third quarter		16,292		17,032
Fourth quarter		16,357		17,240

Item 6 — Selected Financial Data

This is omitted per conditions set forth in general instructions I(1)(a) and (b) of Form 10-K for wholly owned subsidiaries (reduced disclosure format).

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Item 7 — 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 I (1)(a) and (b) of Form 10-K for wholly owned subsidiaries. It is replaced with management’s narrative analysis and the results of operations for the current year as set forth in general instructions I(2)(a) of Form 10-K for wholly owned subsidiaries (reduced disclosure format).

Financial Review

The following discussion and analysis by management focuses on those factors that had a material effect on the financial condition and results of operations during the periods presented, or are expected to have a material impact in the future. It should be read in conjunction with the accompanying financial statements and the related notes to the financial statements.

Forward-Looking Statements

Except for the historical statements contained in this report, the matters discussed in the following discussion and analysis are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements are intended to be identified in this document by the words “anticipate,” “believe,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should,” and similar expressions. Actual results may vary materially. Forward-looking statements speak only as of the date they are made and we do not undertake any obligation to update them to reflect changes that occur after that date. Factors that could cause actual results to differ materially include, but are not limited to: general economic conditions, including the availability of credit and its impact on capital expenditures and the ability of SPS to obtain financing on favorable terms; business conditions in the energy industry; actions of credit rating agencies; competitive factors, including the extent and timing of the entry of additional competition in the markets served by SPS; unusual weather; effects of geopolitical events, including war and acts of terrorism; state, federal and foreign legislative and regulatory initiatives that affect cost and investment recovery, have an impact on rates or have an impact on asset operation or ownership or impose environmental compliance conditions; structures that affect the speed and degree to which competition enters the electric and natural gas markets; costs and other effects of legal and administrative proceedings, settlements, investigations and claims; environmental laws and regulations; actions of accounting regulatory bodies; and the other risk factors listed from time to time by SPS in reports filed with the SEC, including “Risk Factors” in Item 1A of SPS’ Form 10-K for the year ended Dec. 31, 2010 and Exhibit 99.01 to SPS’ Form 10-K for the year ended Dec. 31, 2010.

Results of Operations

SPS’ net income was approximately $78.1 million for 2010, compared with net income of approximately $67.8 million for 2009. The increase is primarily due to electric sales growth, particularly to the commercial and industrial customer class, the reversal of previously established fuel reserves following the approval of certain settlement agreements and lower interest expense, which was partially offset by higher O&M expenses.

Electric Revenues and 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. The design of fuel and purchased power cost recovery mechanisms of the Texas and New Mexico jurisdictions may not allow for complete recovery of all expenses and, therefore, changes in fuel or purchased power costs can impact earnings. The following table details the electric revenues and margin:

(Millions of Dollars)	2010			2009
Electric revenues	$	1,613		$	1,459
Electric fuel and purchased power		(1,024	)		(914	)
Electric margin	$	589		$	545

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The following tables summarize the components of the changes in electric revenues and electric margin for the year ended Dec. 31:

Electric Revenues

(Millions of Dollars)	2010 vs. 2009
Fuel and purchased power cost recovery	$	117
Fuel cost allocation regulatory accruals		15
Firm wholesale		9
Transmission revenue		8
Retail rate increases (New Mexico)		6
Sales mix and demand revenues		6
Retail sales increase (excluding weather impact)		5
Non-fuel riders		(4	)
Other, net		(8	)
Total increase in electric revenue	$	154

Electric Margin

(Millions of Dollars)	2010 vs. 2009
Fuel cost allocation regulatory accruals	$	15
Firm wholesale		9
Retail rate increase (New Mexico)		6
Sales mix and demand revenues		6
Retail sales increase (excluding weather impact)		5
Non-fuel riders		(4	)
Other, net		7
Total increase in base electric margin	$	44

Non-Fuel Operating Expense and Other Items

O&M Expenses — O&M expenses increased $27.4 million, or 12.4 percent, for 2010 compared to 2009. The following summarizes the components of the changes for the year ended Dec. 31:

(Millions of Dollars)	2010 vs. 2009
Higher plant generation costs	$	11
Higher employee benefit expenses		9
Higher labor costs		3
Higher contract labor costs		2
Other, net		2
Total increase in operating and maintenance expenses	$	27

AFUDC — AFUDC increased by approximately $0.5 million for the twelve months of 2010 compared with 2009. This increase was primarily due to larger CWIP balances.

Interest Charges — Interest charges decreased by $7.8 million, or 10.8 percent, for 2010 compared with 2009. The decrease was primarily due to the retirement of long-term debt in March 2009.

Demand Side Management (DSM) Program Expenses — DSM program expenses for 2010 increased by approximately $4.4 million, or 59.9 percent, compared with 2009. The higher expenses are attributable to the continued expansion of programs and regulatory commitments. DSM program expenses are generally recovered in major jurisdictions concurrently through riders and base rates.

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Income Taxes — Income tax expense increased by $8.4 million for 2010, compared with 2009. The increase in income tax expense was primarily due to an increase in pretax income and a write-off of tax benefit previously recorded for Medicare Part D subsidies. The effective tax rate was 38.5 percent for 2010, compared with 37.4 percent for 2009. The higher effective tax rate for 2010 was primarily due to the write-off of tax benefit for Medicare Part D subsidies in 2010. Without this write-off, the effective tax rate for 2010 would have been 37.0 percent.

The effective tax rate for 2010 differs from the statutory federal income tax rate, primarily due to state income tax expense and a write-off of tax benefit previously recorded for Medicare Part D subsidies. The effective tax rate for 2009 differs from the statutory federal income tax rate, primarily due to state income tax expense. See Note 6 to the financial statements for further discussion.

Item 7A — Quantitative and Qualitative Disclosures About Market Risk

Derivatives, Risk Management and Market Risk

In the normal course of business, SPS is exposed to a variety of market risks. Market risk is the potential loss or gain that may occur as a result of changes in the market or fair value of a particular instrument or commodity. All financial and commodity-related instruments, including derivatives, are subject to market risk. These risks, as applicable to SPS, are discussed in further detail in Note 9 to the financial statements.

Commodity Price Risk — SPS is exposed to commodity price risk in its electric operations. Commodity price risk is managed by entering into long- and short-term physical purchase and sales contracts for electric capacity, energy and energy-related products and for various fuels used in the generation and distribution activities. SPS’ risk management policy allows it to manage commodity price risk to the extent such exposure exists.

Short-Term Wholesale and Commodity Trading Risk — SPS conducts an immaterial amount of short-term wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy and energy related instruments. SPS’ risk-management policy allows management to conduct these activities within guidelines and limitations as approved by its risk management committee, which is made up of management personnel not directly involved in the activities governed by the policy.

Interest Rate Risk — SPS is subject to the risk of fluctuating interest rates in the normal course of business. SPS’ risk management policy allows interest rate risk to be managed through the use of fixed rate debt, floating rate debt and interest rate derivatives such as swaps, caps, collars and put or call options.

At Dec. 31, 2010, a 100-basis-point change in the benchmark rate on SPS’ variable rate debt would impact pretax interest expense by approximately $0.5 million annually. See Note 9 to the financial statements for a discussion of SPS’ interest rate derivatives.

Credit Risk — SPS is also exposed to credit risk. Credit risk relates to the risk of loss resulting from counterparties’ nonperformance of their contractual obligations. SPS maintains credit policies intended to minimize overall credit risk and actively monitors these policies to reflect changes and scope of operations. At Dec. 31, 2010, a 10 percent increase or decrease in prices would have no impact on credit exposure.

SPS conducts standard credit reviews for all counterparties. SPS employs additional credit risk control mechanisms when appropriate, such as letters of credit, parental guarantees, standardized master netting agreements and termination provisions that allow for offsetting of positive and negative exposures. Credit exposure is monitored and, when necessary, the activity with a specific counterparty is limited until credit enhancement is provided. Distress in the financial markets could increase SPS’ credit risk.

Item 8 — Financial Statements and Supplementary Data

See 15-1 in Part IV for an index of financial statements included herein.

See Note 16 to the financial statements for summarized quarterly financial data.

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Management Report on Internal Controls Over Financial Reporting

The management of SPS is responsible for establishing and maintaining adequate internal control over financial reporting. SPS’ internal control system was designed to provide reasonable assurance to the company’s management and board of directors regarding the preparation and fair presentation of published financial statements.

All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.

SPS management assessed the effectiveness of the company’s internal control over financial reporting as of Dec. 31, 2010. In making this assessment, it used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control — Integrated Framework. Based on our assessment, we believe that, as of Dec. 31, 2010, the company’s internal control over financial reporting is effective based on those criteria.

/s/ C. RILEY HILL		/s/ DAVID M. SPARBY
C. Riley Hill		David M. Sparby
President and Chief Executive Officer		Vice President and Chief Financial Officer
Feb. 28, 2011		Feb. 28, 2011

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Stockholder

Southwestern Public Service Company

We have audited the accompanying balance sheets and statements of capitalization of Southwestern Public Service Company (the “Company”) as of December 31, 2010 and 2009, and the related statements of income, common stockholder’s equity and comprehensive income, and cash flows for each of the three years in the period ended December 31, 2010. Our audits also included the financial statement schedule listed in the Index at Item 15. These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such financial statements present fairly, in all material respects, the financial position of Southwestern Public Service Company as of December 31, 2010 and 2009, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2010, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

/s/ DELOITTE & TOUCHE LLP

Minneapolis, Minnesota

Feb. 28, 2011

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SOUTHWESTERN PUBLIC SERVICE CO.

STATEMENTS OF INCOME

(amounts in thousands of dollars)

	Year Ended Dec. 31,
	2010			2009			2008

Operating revenues	$	1,612,990		$	1,459,223		$	1,992,774

Operating expenses
Electric fuel and purchased power		1,023,938			914,350			1,530,999
Other operating and maintenance expenses		249,071			221,681			207,753
Demand side management program expenses		11,625			7,270			8,677
Depreciation and amortization		103,935			104,602			98,657
Taxes (other than income taxes)		40,984			38,503			41,238
Total operating expenses		1,429,553			1,286,406			1,887,324

Operating income		183,437			172,817			105,450

Other income, net		27			264			5,829
Allowance for funds used during construction — equity		4,188			4,082			-

Interest charges and financing costs
Interest charges — includes other financing costs of $2,635, $2,653 and $2,430, respectively		63,912			71,688			61,090
Allowance for funds used during construction — debt		(3,193	)		(2,770	)		(2,580	)
Total interest charges and financing costs		60,719			68,918			58,510

Income before income taxes		126,933			108,245			52,769
Income taxes		48,866			40,495			20,977
Net income	$	78,067		$	67,750		$	31,792

See Notes to Financial Statements

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SOUTHWESTERN PUBLIC SERVICE CO.

STATEMENTS OF CASH FLOWS

(amounts in thousands of dollars)

	Year Ended Dec. 31,
	2010			2009			2008
Operating activities
Net income	$	78,067		$	67,750		$	31,792
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization		106,207			106,897			103,116
Demand side management program amortization		2,034			1,793			6,942
Deferred income taxes		25,312			30,373			8,423
Amortization of investment tax credits		(341	)		(298	)		(305	)
Allowance for equity funds used during construction.		(4,188	)		(4,082	)		-
Provision for bad debts		3,990			3,765			4,745
Net realized and unrealized hedging and derivative transactions		268			(2,698	)		3,234
Changes in operating assets and liabilities:
Accounts receivable		1,691			11,919			3,419
Accrued unbilled revenues		(4,399	)		(7,922	)		10,462
Inventories		(2,702	)		19,935			(29,739	)
Prepayments and other		10,920			(10,558	)		2,080
Accounts payable		(17,015	)		(5,788	)		15,914
Net regulatory assets and liabilities		(20,082	)		43,946			34,847
Other current liabilities		3,902			(3,236	)		(4,769	)
Change in other noncurrent assets		(2,868	)		(11,067	)		(12,069	)
Change in other noncurrent liabilities		(3,466	)		(19,218	)		6,527
Net cash provided by operating activities		177,330			221,511			184,619
Investing activities
Utility capital/construction expenditures		(309,408	)		(211,866	)		(193,501	)
Proceeds from the sale of assets		87,823			-			-
Allowance for equity funds used during construction		4,188			4,082			-
Investments in utility money pool arrangement		(204,200	)		(990,800	)		(247,200	)
Receipts from utility money pool arrangement		281,200			1,004,300			156,700
Net cash used in investing activities		(140,397	)		(194,284	)		(284,001	)
Financing activities
Proceeds from (repayment of) short-term borrowings, net		49,000			-			(123,000	)
Proceeds from issuance of long-term debt		-			-			246,119
Repayment of long-term debt, including reacquisition premiums		(25,000	)		(100,057	)		-
Borrowings under utility money pool arrangement		483,200			-			672,700
Repayments under utility money pool arrangement		(483,200	)		-			(678,200	)
Capital contributions from parent		583			16,243			173,639
Dividends paid to parent		(67,101	)		(66,845	)		(61,795	)
Net cash (used in) provided by financing activities		(42,518	)		(150,659	)		229,463

Net (decrease) increase in cash and cash equivalents		(5,585	)		(123,432	)		130,081
Cash and cash equivalents at beginning of year		7,363			130,795			714
Cash and cash equivalents at end of year	$	1,778		$	7,363		$	130,795
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized)	$	(57,969	)	$	(69,619	)	$	(59,530	)
Cash paid for income taxes, net		(7,277	)		(20,118	)		(15,735	)
Supplemental disclosure of non-cash investing transactions:
Property, plant and equipment additions in accounts payable	$	9,539		$	12,432		$	6,243

See Notes to Financial Statements

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SOUTHWESTERN PUBLIC SERVICE CO.

BALANCE SHEETS

(amounts in thousands of dollars)

	Dec. 31,
	2010			2009
Assets
Current assets
Cash and cash equivalents	$	1,778		$	7,363
Investments in utility money pool arrangement		-			77,000
Accounts receivable, net		44,871			47,065
Accounts receivable from affiliates		1,610			5,097
Accrued unbilled revenues		110,184			105,785
Inventories		29,849			27,147
Regulatory assets		21,547			16,476
Derivative instruments		7,892			8,926
Deferred income taxes		19,051			32,400
Prepayments and other		5,006			15,927
Total current assets		241,788			343,186

Property, plant and equipment, net		2,401,266			2,260,984

Other assets
Regulatory assets		283,207			271,417
Derivative instruments		64,734			67,625
Other		10,668			8,783
Total other assets		358,609			347,825
Total assets	$	3,001,663		$	2,951,995

Liabilities and Equity
Current liabilities
Current portion of long-term debt	$	44,500		$	-
Short-term debt		49,000			-
Accounts payable		134,322			163,253
Accounts payable to affiliates		24,525			14,625
Regulatory liabilities		53,197			65,121
Taxes accrued		19,867			18,209
Accrued interest		12,128			12,371
Dividends payable to parent		16,358			17,240
Derivative instruments		3,601			3,588
Other		21,349			20,125
Total current liabilities		378,847			314,532

Deferred credits and other liabilities
Deferred income taxes		541,204			529,235
Deferred investment tax credits		2,051			2,392
Regulatory liabilities		134,952			113,742
Asset retirement obligations		21,131			18,757
Derivative instruments		44,991			48,654
Pension and employee benefit obligations		52,280			44,276
Other		10,827			8,450
Total deferred credits and other liabilities		807,436			765,506

Commitments and contingent liabilities
Capitalization
Long-term debt		853,267			922,447
Common stock – authorized 200 shares of $1.00 par value; outstanding 100 shares		-			-
Additional paid in capital		693,531			692,948
Retained earnings		270,257			258,409
Accumulated other comprehensive loss		(1,675	)		(1,847	)
Total common stockholder's equity		962,113			949,510
Total liabilities and equity	$	3,001,663		$	2,951,995

See Notes to Financial Statements

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SOUTHWESTERN PUBLIC SERVICE CO.

STATEMENTS OF COMMON STOCKHOLDER’S EQUITY

AND COMPREHENSIVE INCOME

(amounts in thousands of dollars, except share data)

	Common Stock Issued									Accumulated			Total
					Additional					Other			Common
					Paid In		Retained			Comprehensive			Stockholder's
	Shares		Par Value		Capital		Earnings			Income (Loss)			Equity
Balance at Dec. 31, 2007		100	$	-	$	503,066	$	289,092		$	(6,005	)	$	786,153
Adoption of new accounting guidance for endorsement split-dollar life insurance,
net of tax of $(174)								(276	)					(276	)
Net income								31,792						31,792
Net derivative instrument fair value changes during the period, net of tax of $253											446			446
Comprehensive income for 2008														32,238
Common dividends declared to parent								(61,449	)					(61,449	)
Contribution of capital by parent						173,639								173,639
Balance at Dec. 31, 2008		100	$	-	$	676,705	$	259,159		$	(5,559	)	$	930,305
Net income								67,750						67,750
Net derivative instrument fair value changes during the period, net of tax of $2,093											3,712			3,712
Comprehensive income for 2009														71,462
Common dividends declared to parent								(68,500	)					(68,500	)
Contribution of capital by parent						16,243								16,243
Balance at Dec. 31, 2009		100	$	-	$	692,948	$	258,409		$	(1,847	)	$	949,510
Net income								78,067						78,067
Net derivative instrument fair value changes during the period, net of tax of $96											172			172
Comprehensive income for 2010														78,239
Common dividends declared to parent								(66,219	)					(66,219	)
Contribution of capital by parent						583								583
Balance at Dec. 31, 2010		100	$	-	$	693,531	$	270,257		$	(1,675	)	$	962,113

See Notes to Financial Statements

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SOUTHWESTERN PUBLIC SERVICE CO.

STATEMENTS OF CAPITALIZATION

(amounts in thousands of dollars)

	Dec. 31,
	2010			2009
Long-Term Debt
Unsecured Senior E Notes, due Oct. 1, 2016, 5.6%	$	200,000		$	200,000
Unsecured Senior G Notes, due Dec. 1, 2018, 8.75%		250,000			250,000
Unsecured Senior C and D Notes, due Oct. 1, 2033, 6%		100,000			100,000
Unsecured Senior F Notes, due Oct. 1, 2036, 6%		250,000			250,000
Pollution control obligations, securing pollution control revenue bonds, due:
July 1, 2011, 5.2%		44,500			44,500
July 1, 2016, 8.5%		-			25,000
Sept. 1, 2016, 5.75%		57,300			57,300
Unamortized discount		(4,033	)		(4,353	)
Total		897,767			922,447
Less current maturities		44,500			-
Total long-term debt	$	853,267		$	922,447

Common Stockholder's Equity
Common stock — authorized 200 shares of $1.00 par value; outstanding 100 shares in 2010 and 2009	$	-		$	-
Additional paid in capital		693,531			692,948
Retained earnings		270,257			258,409
Accumulated other comprehensive loss		(1,675	)		(1,847	)
Total common stockholder's equity	$	962,113		$	949,510

See Notes to Financial Statements

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NOTES TO FINANCIAL STATEMENTS

1. Summary of Significant Accounting Policies

Business and System of Accounts — SPS is principally engaged in the generation, purchase, transmission, distribution and sale of electricity. SPS is subject to regulation by the FERC and state utility commissions. All of SPS’ accounting records conform to the FERC uniform system of accounts or to systems required by various state regulatory commissions, which are the same in all material respects.

Revenue Recognition — Revenues related to the sale of energy are generally recorded when service is rendered or energy is delivered to customers. However, the determination of the energy sales to individual customers is based on the reading of their meter, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated and the corresponding unbilled revenue is recognized. SPS presents its revenue net of any excise or other fiduciary-type taxes or fees.

SPS has various rate-adjustment mechanisms in place that currently provide for the recovery of natural gas and other electric fuel costs, as well as purchased energy costs. These cost-adjustment tariffs may increase or decrease the level of costs recovered through base rates and are revised periodically for any difference between the total amount collected under the clauses and the recoverable costs incurred. Where applicable, under governing state regulatory commission rate orders, fuel cost over-recoveries (the excess of fuel revenue billed to customers over fuel costs incurred) are deferred as regulatory liabilities and under-recoveries (the excess of fuel costs incurred over fuel revenues billed to customers) are deferred as regulatory assets. A summary of significant rate-adjustment mechanisms follows:

●

In Texas, SPS recovers fuel and purchased energy costs through a fixed fuel and purchased energy recovery factor, which is part of SPS’ retail electric rates. The Texas retail fuel factors can change up to three times per year based on the projected costs of natural gas. In January 2010, the PUCT approved recovery of certain transmission investments and other transmission costs through the TCRF rider. In New Mexico, the NMPRC has authorized SPS to use a monthly adjustment factor for FPPCAC to recover fuel and purchased power costs, subject to the ongoing NMPRC approval and audits.

●	SPS sells firm power and energy in wholesale markets, which are regulated by the FERC. Certain of these rates include monthly wholesale fuel cost-recovery mechanisms.

Commodity Trading Operations — All applicable gains and losses related to commodity trading activities, whether or not settled physically, are shown on a net basis in the statements of income.

Pursuant to the JOA approved by the FERC, some of the commodity trading margins from SPS are apportioned to NSP-Minnesota and PSCo. Commodity trading activities are not associated with energy produced from SPS’ generation assets or energy and capacity purchased to serve native load. Commodity trading contracts are recorded at fair market value and commodity trading results include the impact of all margin-sharing mechanisms. For more information, see Note 9 to the financial statements.

Fair Value Measurements — SPS presents cash equivalents, interest rate derivatives and commodity derivatives at estimated fair values in its financial statements. Cash equivalents are recorded at cost plus accrued interest to approximate fair value. Changes in the observed trading prices and liquidity of cash equivalents, including commercial paper and money market funds, are also monitored as additional support for determining fair value, and losses are recorded in earnings if fair value falls below recorded cost. For interest rate derivatives, quoted prices based primarily on observable market interest rate curves are used as a primary input to establish fair value. For commodity derivatives, the most observable inputs available are generally used to determine the fair value of each contract. In the absence of a quoted price for an identical contract in an active market, Xcel Energy may use quoted prices for similar contracts, or internally prepared valuation models to determine fair value.

Types of and Accounting for Derivative Instruments — SPS uses derivative instruments in connection with its utility commodity price, interest rate, short-term wholesale and commodity trading activities, including forward contracts, futures, swaps and options. All derivative instruments not designated and qualifying for the normal purchases and normal sales exception, as defined by the accounting guidance for derivatives and hedging, are recorded on the balance sheets at fair value as derivative instruments valuation. This includes certain instruments used to mitigate market risk for the utility operations and all instruments related to the commodity trading operations. The classification of changes in fair value for those derivative instruments is dependent on the designation of a qualifying hedging relationship. Changes in fair value of derivative instruments not designated in a qualifying hedging relationship are reflected in current earnings or as a regulatory asset or liability. The classification is dependent on the applicability of specific regulation.

Gains or losses on hedging transactions for the sale 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.

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Cash Flow Hedges — Qualifying hedging relationships are designated as a hedge of a forecasted transaction or future cash flow (cash flow hedge). The accounting for derivatives requires that the hedging relationship be highly effective and that a company formally designate a hedging relationship to apply hedge accounting. SPS formally documents all hedging relationships in accordance with this guidance. The documentation includes, among other factors, the identification of the hedging instrument and the hedged transaction, as well as the risk management objectives and strategies for undertaking the hedging transaction. In addition, at inception and on a quarterly basis, SPS formally assesses whether the derivative instruments being used are highly effective in offsetting changes in the cash flows of the hedged items.

Changes in the fair value of a derivative designated and qualified as a cash flow hedge, to the extent effective are included in OCI, or deferred as a regulatory asset or liability based on recovery mechanisms until earnings are affected by the hedged transaction. SPS discontinues hedge accounting prospectively when it has determined that a derivative no longer qualifies as an effective hedge, or when it is no longer probable that the hedged forecasted transaction will occur. To test the effectiveness of hedges, a hypothetical hedge is used to mirror all the critical terms of the hedged transaction and the dollar-offset method is utilized to assess the effectiveness of the actual hedge at inception and on an ongoing basis. Gains and losses related to discontinued hedges that were previously deferred in OCI or deferred as regulatory assets or liabilities will remain deferred until the hedged transaction is reflected in earnings, unless it is probable that the hedged forecasted transaction will not occur, in which case associated deferred amounts are immediately recognized in current earnings.

Normal Purchases and Normal Sales — SPS enters into contracts for the purchase and sale of commodities for use in their business operations. Derivatives and hedging accounting guidance 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 derivative accounting as normal purchases or normal sales.

SPS evaluates all of its contracts at inception to determine if they are derivatives and if they meet the normal purchases and normal sales designation requirements. None of the contracts entered into within the commodity trading operations qualify for a normal purchases and normal sales designation.

For further discussion of SPS’ risk management and derivative activities, see Note 9 to the financial statements.

Property, Plant and Equipment and Depreciation — Property, plant and equipment is stated at original cost. The cost of plant includes direct labor and materials, contracted work, overhead costs and applicable interest expense. The cost of plant retired is charged to accumulated depreciation and amortization. Amounts recovered in rates for future removal costs are recorded as regulatory liabilities. Significant additions or improvements extending asset lives are capitalized, while repairs and maintenance costs are charged to expense as incurred. Maintenance and replacement of items determined to be less than units of property are charged to operating expenses as incurred. Planned major maintenance activities are charged to operating expense unless the cost represents the acquisition of an additional unit of property or the replacement of an existing unit of property. Property, plant and equipment also includes costs associated with property held for future use.

SPS records depreciation expense related to its plant using the straight-line method over the plant’s useful life. Actuarial and semi-actuarial life studies are performed on a periodic basis and submitted to the state and federal commissions for review. Upon acceptance by the various commissions, the resulting lives and net salvage rates are used to calculate depreciation. Depreciation expense, expressed as a percentage of average depreciable property, was 2.7, 2.6 and 2.8 percent for the years ended Dec. 31, 2010, 2009 and 2008 respectively.

AFUDC — AFUDC represents the cost of capital used to finance utility construction activity. AFUDC is computed by applying a composite pretax rate to qualified CWIP. The amount of AFUDC capitalized as a utility construction cost is credited to other nonoperating income (for equity capital) and interest charges (for debt capital). AFUDC amounts capitalized are included in SPS’ rate base for establishing utility service rates.

Leases — SPS evaluates a variety of contracts for lease classification at inception, including purchased power agreements and rental arrangements for office space, vehicles, and equipment. Contracts determined to contain a lease because of per unit pricing that is other than fixed or market price, terms regarding the use of a particular asset, and other factors are evaluated further to determine if the arrangement is a capital lease.

Variable Interest Entities — Effective Jan. 1, 2010, SPS adopted new guidance on consolidation of variable interest entities. The guidance requires enterprises to consider the activities that most significantly impact an entity’s financial performance and power to direct those activities, when determining whether an enterprise is a variable interest entity’s primary beneficiary.

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Under its purchased power agreements, SPS purchases power from independent power producing entities that own natural gas fueled power plants. Through various mechanisms in certain purchased power agreements, SPS incurs variable fuel costs, and consequently these mechanisms have been determined to create variable interests in the independent power producing entities. Certain independent power producing entities are therefore variable interest entities. SPS has concluded that these entities are not required to be consolidated in its financial statements because it does not have the power to direct the activities that most significantly impact the entities’ economic performance.

Environmental Costs — Environmental costs are recorded when it is probable SPS is liable for the costs and the liability can be reasonably estimated. Costs are deferred as a regulatory asset if it is probable that the costs will be recovered from customers in future rates. Otherwise, the costs are expensed. If an environmental expense is related to facilities currently in use, such as emission-control equipment, the cost is capitalized and depreciated over the life of the plant.

Estimated remediation costs, excluding inflationary increases, are recorded. The estimates are based on experience, an assessment of the current situation and the technology currently available for use in the remediation. The recorded costs are regularly adjusted as estimates are revised and remediation proceeds. If several designated responsible parties exist, costs are estimated and recorded only for SPS’ share of the cost. Any future costs of restoring sites where operation may extend indefinitely are treated as a capitalized cost of plant retirement. The depreciation expense levels recoverable in rates include a provision for removal expenses, which may include final remediation costs. Removal costs recovered in rates are classified as a regulatory liability.

Legal Costs — Litigation accruals are recorded when it is probable SPS is liable for the costs and the liability can be reasonably estimated. External legal fees related to settlements are expensed as incurred.

Income Taxes — SPS accounts for income taxes using the asset and liability method, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the financial statements. SPS defers income taxes for all temporary differences between pretax financial and taxable income, and between the book and tax bases of assets and liabilities. SPS uses the tax rates that are scheduled to be in effect when the temporary differences are expected to reverse. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period that includes the enactment date.

Deferred tax assets are reduced by a valuation allowance if, based on the weight of available evidence, it is more likely than not that some portion or all of the deferred tax asset will not be realized. In making such a determination, all available positive and negative evidence, including scheduled reversals of deferred tax liabilities, projected future taxable income, tax planning strategies and recent financial operations, is considered.

Investment tax credits are deferred and their benefits amortized over the book depreciable lives of the related property. Utility rate regulation also has resulted in the recognition of certain regulatory assets and liabilities related to income taxes, which are summarized in Note 13 to the financial statements. For more information on income taxes, see Note 6 to the financial statements.

SPS follows the applicable accounting guidance to measure and disclose uncertain tax positions that SPS has taken or expects to take in its income tax returns. In accordance with this guidance, SPS recognizes a tax position in its financial statements when it is more likely than not that the position will be sustained upon examination based on the technical merits of the position. Recognition of changes in uncertain tax positions are reflected as a component of income tax expense.

SPS reports interest and penalties related to income taxes within the other income and interest charges sections in the statements of income.

Xcel Energy and its subsidiaries, including SPS, file consolidated federal income tax returns and combined and separate state income tax returns. Federal income taxes paid by Xcel Energy, as parent of the Xcel Energy consolidated group, are allocated to the Xcel Energy subsidiaries based on separate company computations of tax. A similar allocation is made for state income taxes paid by Xcel Energy in connection with combined state filings. The holding company also allocates its own income tax benefits to its direct subsidiaries based on the relative positive tax liabilities of the subsidiaries.

Use of Estimates — In recording transactions and balances resulting from business operations, SPS uses estimates based on the best information available. Estimates are used for such items as plant depreciable lives, AROs, decommissioning, tax provisions, uncollectible amounts, environmental costs, unbilled revenues, jurisdictional fuel and energy cost allocations and actuarially determined benefit costs. The recorded estimates are revised when better information becomes available or when actual amounts can be determined. Those revisions can affect operating results. The depreciable lives of certain plant assets are reviewed annually and revised, if appropriate.

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Cash and Cash Equivalents — SPS considers investments in certain instruments, including commercial paper and money market funds, with a remaining maturity of three months or less at the time of purchase, to be cash equivalents.

Inventory — All inventory is recorded at average cost.

Regulatory Accounting — SPS accounts for certain income and expense items in accordance with accounting guidance for regulated operations. Under this guidance:

·	Certain costs, which would otherwise be charged to expense, are deferred as regulatory assets based on the expected ability to recover the costs in future rates; and

·	Certain credits, which would otherwise be reflected as income, are deferred as regulatory liabilities based on the expectation the amounts will be returned to customers in future rates, or because the amounts were collected in rates prior to the costs being incurred.

Estimates of recovering deferred costs and returning deferred credits are based on specific ratemaking decisions or precedent for each item. Regulatory assets and liabilities are amortized consistent with the treatment in the rate setting process.

If restructuring or other changes in the regulatory environment occur, SPS may no longer be eligible to apply this accounting treatment and may be required to eliminate such regulatory assets and liabilities from its balance sheet. Such changes could have a material effect on SPS’ results of operations in the period the write-offs are recorded. See more discussion of regulatory assets and liabilities in Note 13 to the financial statements.

Conservation Programs — SPS has implemented programs in its jurisdictions to assist customers in conserving energy and reducing peak demand on the electric system. These programs include, but are not limited to commercial process efficiency and lighting updates, and residential rebates for participation in air conditioner interruption and energy-efficient appliances.

The costs incurred for some DSM programs are deferred as permitted by the applicable regulatory jurisdiction. For those programs, costs are deferred if it is probable that future revenue, in an amount at least equal to the deferred amount, will be provided to permit recovery of the previously incurred cost, rather than to provide for expected future amounts of similar programs. For incentive programs designed to allow recovery of lost margins and/or conservation performance incentives, recorded revenues are limited to those amounts expected to be collected within twenty four months following the end of the annual period in which they are earned. SPS recovers approved conservation program costs in base rate revenue or through a rider.

Deferred Financing Costs — Other assets included deferred financing costs of approximately $5.9 million and $6.9 million, net of amortization, at Dec. 31, 2010 and 2009, respectively. SPS is amortizing these financing costs over the remaining maturity periods of the related debt.

Debt premiums, discounts and expenses are amortized over the life of the related debt. The premiums, discounts and expenses associated with refinanced debt are deferred and amortized over the life of the related new issuance, in accordance with regulatory guidelines.

Guarantees — SPS recognizes, upon issuance or modification of a guarantee, a liability for the fair market value of the obligations that have been assumed in issuing the guarantee. This liability includes consideration of specific triggering events and other conditions which may modify the ongoing obligation to perform under the guarantee.

The obligation recognized is reduced over the term of the guarantee as SPS is released from risk under the guarantee. Refer to note 10 to the financial statements for specific details of issued guarantees.

Accounts Receivable and Allowance for Bad Debts — Accounts receivable are stated at the actual billed amount net of an allowance for bad debts. SPS establishes an allowance for uncollectible receivables based on a policy that reflects its expected exposure to the credit risk of customers.

Renewable Energy Credits — RECs are marketable environmental commodities that represent proof that energy was generated from eligible renewable energy sources. RECs are awarded upon delivery of the associated energy and can be bought and sold. RECs are typically used as a form of measurement of compliance to RPS enacted by those states that are encouraging construction and consumption from renewable energy sources, but can also be sold separately from the energy produced. Currently, SPS acquires RECs from the generation or purchase of renewable power.

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When RECs are acquired in the course of generation or purchased as a result of meeting load obligations, they are recorded as inventory at cost. RECs acquired for trading purposes are recorded as other investments and are also recorded at cost. The cost of RECs that are utilized for compliance purposes is recorded as electric fuel and purchased power expense. The net margin on sales of RECs for trading purposes is recorded as electric utility operating revenues net of any margin sharing requirements. As a result of certain state regulatory orders, SPS reduces recoverable fuel costs for the value of certain RECs and records the cost of future compliance requirements that are recoverable in future rates as regulatory assets.

Emission Allowances — Emission allowances are recorded at cost, including the annual SO2 and NOx emission allowance entitlement received at no cost from the EPA. SPS follows the inventory accounting model for all emission allowances. The sales of allowances are included in electric utility operating revenues and the operating activities section of the statements of cash flows.

Reclassifications — Certain prior year amounts have been reclassified to conform to the current year presentation, including amounts related to deferred income taxes, regulatory assets and regulatory liabilities in the balance sheet and statements of cash flows. These reclassifications did not have an impact on net income.

Subsequent Events — Management has evaluated the impact of events occurring after Dec. 31, 2010 up to the date of issuance of these financial statements. These statements contain all necessary adjustments and disclosures resulting from that evaluation.

2. Accounting Pronouncements

Consolidation of Variable Interest Entities — In June 2009, the FASB issued new guidance on consolidation of variable interest entities. The guidance affects various elements of consolidation, including the determination of whether an entity is a variable interest entity and whether an enterprise is a variable interest entity’s primary beneficiary. These updates to the ASC were effective for interim and annual periods beginning after Nov. 15, 2009. SPS implemented the guidance on Jan. 1, 2010, and the implementation did not have a material impact on its financial statements. For further information and required disclosures regarding variable interest entities, see Note 12 to the financial statements.

Fair Value Measurement Disclosures — In January 2010, the FASB issued Fair Value Measurements and Disclosures (Topic 820) — Improving Disclosures about Fair Value Measurements (ASU No. 2010-06), which updates the Codification to require new disclosures for assets and liabilities measured at fair value. The requirements include expanded disclosure of valuation methodologies for fair value measurements, transfers between levels of the fair value hierarchy, and gross rather than net presentation of certain changes in Level 3 fair value measurements. The updates to the Codification contained in ASU No. 2010-06 were effective for interim and annual periods beginning after Dec. 15, 2009, except for requirements related to gross presentation of certain changes in Level 3 fair value measurements, which are effective for interim and annual periods beginning after Dec. 15, 2010. SPS implemented the portions of the guidance required on Jan. 1, 2010, and the implementation did not have a material impact on its financial statements. For further information and required disclosures, see Note 9 to the financial statements.

3. Selected Balance Sheet Data

(Thousands of Dollars)	Dec. 31, 2010			Dec. 31, 2009
Accounts receivable, net
Accounts receivable	$	49,966		$	51,480
Less allowance for bad debts		(5,095	)		(4,415	)
	$	44,871		$	47,065
Inventories
Materials and supplies	$	15,093		$	15,737
Fuel		14,756			11,410
	$	29,849		$	27,147
Property, plant and equipment, net
Electric plant	$	3,826,202		$	3,777,623
Construction work in progress		221,025			95,652
Total property, plant and equipment		4,047,227			3,873,275
Less accumulated depreciation		(1,645,961	)		(1,612,291	)
	$	2,401,266		$	2,260,984

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4. Borrowings and Other Financing Instruments

Money Pool — Xcel Energy and its utility subsidiaries have established a money pool arrangement that allows for short-term investments in and borrowings from the utility subsidiaries between each other. The holding company may make investments in the utility subsidiaries at market-based interest rates. However, the money pool arrangement does not allow the utility subsidiaries to make investments in the holding company.

The following table presents the money pool investments for SPS:

(Millions of Dollars)	Dec. 31, 2010		Dec. 31, 2009
Money pool investments	$	-	$	77
Weighted average interest rate		N/A		0.36	%
Money pool borrowing limit	$	100	$	100

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

(Millions of Dollars)	Dec. 31, 2010			Dec. 31, 2009
Commercial paper outstanding	$	49		$	-
Weighted average interest rate		0.37	%		N/A
Commercial paper borrowing limit	$	248		$	248

Credit Facilities — SPS must have revolving credit facilities in place at least equal to the amount of its respective commercial paper borrowing limits and cannot issue commercial paper in an aggregate amount exceeding available capacity under these credit agreements. All credit facility bank borrowings and outstanding commercial paper reduce the available capacity under the respective credit facilities as presented in the table below. At Dec. 31, 2010 and Dec. 31, 2009, there were no credit facility bank borrowings outstanding.

At Dec. 31, 2010, SPS had the following committed credit facility in effect, in millions of dollars:

Credit Facility				Drawn*				Available			Original Term		Maturity
$	248			$	49			$	199		Five year		December 2011

* Includes outstanding commercial paper and issued and outstanding letters of credit.

The line of credit provides short-term financing in the form of notes payable to banks, letters of credit and back-up support for commercial paper borrowings. SPS has the right to request an extension of the final maturity date by one year. The maturity extension is subject to majority bank group approval.

The credit facility has one financial covenant requiring that SPS’ debt-to-total capitalization ratio be less than or equal to 65 percent. SPS was in compliance as its debt-to-total capitalization ratio was 50 percent and 49 percent at Dec. 31, 2010 and 2009, respectively. If SPS does not comply with the covenant, an event of default may be declared and it not remedied, and any outstanding amounts due under the facility can be declared due by the lender.

The credit facility has a cross default provision that provides Xcel Energy will be in default on its borrowings under the facility if any of its subsidiaries, comprising more than 15 percent of the consolidated assets of Xcel Energy on a consolidated basis, defaults on any of its indebtedness greater than $50 million.

·	The interest rate is based on either the agent bank’s prime rate, or the applicable LIBOR plus a borrowing margin as based on SPS’ applicable debt rating; this is 35 basis points.

·	The commitment fees, also based on long-term credit ratings, are calculated for the unused portion of the credit facility at 8 basis points for SPS.

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At Dec. 31, 2010, SPS had no direct borrowings on this line of credit; however, the credit facility was used to provide back-up support for $49.0 million of commercial paper outstanding. At Dec. 31, 2009, SPS had no direct borrowings on this line of credit and no outstanding commercial paper; however, the credit facility was used to provide back-up support for $10.0 million of letters of credit.

Xcel Energy plans to syndicate new credit agreements at the Holding Company, NSP-Minnesota, PSCo, SPS and NSP-Wisconsin during the first quarter of 2011 to replace the existing agreements. The total anticipated size of the new credit facilities will be approximately $2.45 billion, of which $300 million is related to SPS.

Certain SPS payments under its pollution control obligations are pledged to secure obligations of the Red River Authority of Texas.

Long-Term Borrowings

In February 2010, SPS redeemed its $25 million pollution control obligations, securing pollution control revenue bonds, due July 1, 2016. During the next five years, SPS has long-term debt maturities of $44.5 million due in 2011.

5. Preferred Stock

SPS has authorized the issuance of preferred stock.

Shares			Shares
Authorized	Par Value		Outstanding
10,000,000	$	1.00	None

6. Income Taxes

Medicare Part D Subsidy Reimbursements — In March 2010, the Patient Protection and Affordable Care Act was signed into law. The law includes provisions to generate tax revenue to help offset the cost of the new legislation. One of these provisions reduces the deductibility of retiree health care costs to the extent of federal subsidies received by plan sponsors that provide retiree prescription drug benefits equivalent to Medicare Part D coverage, beginning in 2013. Based on this provision, SPS is subject to additional taxes and is required to reverse previously recorded tax benefits in the period of enactment.

SPS expensed approximately $1.9 million of previously recognized tax benefits relating to Medicare Part D subsidies during the first quarter of 2010. SPS does not expect the $1.9 million of additional tax expense to recur in future periods.

Federal Audit — SPS is a member of the Xcel Energy affiliated group that files a consolidated federal income tax return. During the first quarter of 2010, the IRS completed an examination of Xcel Energy’s federal income tax returns of tax years 2006 and 2007. The IRS did not propose any material adjustments for those tax years. The statute of limitations applicable to Xcel Energy’s 2006 federal income tax return expired in August 2010. The statute of limitations applicable to Xcel Energy’s 2007 federal income tax return expires in September 2011. The IRS commenced an examination of tax years 2008 and 2009 in the third quarter of 2010. As of Dec. 31, 2010, the IRS had not proposed any material adjustments to tax years 2008 and 2009.

State Audits — SPS is a member of the Xcel Energy affiliated group that files consolidated state income tax returns. As of Dec. 31, 2010, SPS’ earliest open tax year that is subject to examination by state taxing authorities under applicable statutes of limitations is 2006. During the second quarter of 2010, the state of Texas completed its audit of tax years 2006 and 2007. No change in tax liability was proposed. As of Dec. 31, 2010, there were no state income tax audits in progress.

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

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

(Millions of Dollars)	Dec. 31, 2010		Dec. 31, 2009
Unrecognized tax benefit - Permanent tax positions	$	0.2	$	0.2
Unrecognized tax benefit - Temporary tax positions		4.1		2.7
Unrecognized tax benefit balance	$	4.3	$	2.9

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

(Millions of Dollars)	2010			2009			2008
Balance at Jan. 1	$	2.9		$	3.5		$	2.3
Additions based on tax positions related to the current year		1.3			1.4			0.9
Reductions based on tax positions related to the current year		-			-			(0.1	)
Additions for tax positions of prior years		0.2			0.8			0.5
Reductions for tax positions of prior years		(0.1	)		(0.1	)		(0.1	)
Settlements with taxing authorities		-			(2.7	)		-
Balance at Dec. 31	$	4.3		$	2.9		$	3.5

The unrecognized tax benefit amounts were reduced by the tax benefits associated with NOL and tax credit carryforwards. The amounts of tax benefits associated with NOL and tax credit carryfowards are as follows:

(Millions of Dollars)		Dec. 31, 2010				Dec. 31, 2009
NOL and tax credit carryforwards		$	(0.1	)		$	(0.1	)

The increase in the unrecognized tax benefit balance of $1.4 million in 2010 was due to the addition of similar uncertain tax positions related to current and prior years’ activity. SPS’ amount of unrecognized tax benefits could significantly change in the next 12 months as the IRS audit progresses and state audits resume. At this time, due to the uncertain nature of the audit process, it is not reasonably possible to estimate an overall range of possible change.

The payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryforwards. A reconciliation of the beginning and ending amount of the payable for interest related to unrecognized tax benefits is as follows:

(Millions of Dollars)	2010			2009			2008
Payable for interest related to unrecognized tax benefits at Jan. 1	$	(0.1	)	$	(0.3	)	$	(0.1	)
Interest income (expense) related to unrecognized tax benefits		(0.1	)		0.2			(0.2	)
Payable for interest related to unrecognized tax benefits at Dec. 31	$	(0.2	)	$	(0.1	)	$	(0.3	)

No amounts were accrued for penalties related to unrecognized tax benefits as of Dec. 31, 2010, 2009 or 2008.

Other Income Tax Matters — NOL amounts represent the amount of the tax loss that is carried forward and tax credits represent the deferred tax asset. NOL and tax credit carryforwards as of Dec. 31 were as follows:

(Millions of Dollars)	2010			2009
Federal NOL carryforward	$	5.9		$	5.9
Federal tax credit carryforwards		1.1			0.7
State NOL carryforwards		17.9			9.3
Valuation allowance for state NOL carryforwards		(1.3	)		(3.7	)

The federal carryforward periods expire between 2021 and 2030. The state carryforward periods expire between 2011 and 2019.

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Total income tax expense from operations differs from the amount computed by applying the statutory federal income tax rate to income before income tax expense. The following reconciles such differences for the years ending Dec. 31:

	2010			2009			2008
Federal statutory rate		35.0	%		35.0	%		35.0	%
Increases (decreases) in tax from:
Regulatory differences - utility plant items		0.2			0.2			3.5
State income taxes, net of federal income tax benefit		1.8			2.7			4.5
Resolution of income tax audits and other		0.1			0.2			(2.1	)
Tax credit recognized, net of federal income tax expense		(0.4	)		(0.4	)		(0.8	)
Change in unrecognized tax benefits		-			(0.2	)		0.2
Previously recognized Medicare Part D subsidies		1.5			-			-
Other, net		0.3			(0.1	)		(0.5	)
Effective income tax rate		38.5	%		37.4	%		39.8	%

The components of income tax expense for the years ending Dec. 31 were:

(Thousands of Dollars)	2010			2009			2008
Current federal tax expense	$	19,850		$	6,922		$	9,810
Current state tax expense		2,669			4,145			1,800
Current change in unrecognized tax expense (benefit)		1,376			(647	)		1,249
Deferred federal tax expense		26,050			29,234			9,589
Deferred state tax expense		747			870			109
Deferred change in unrecognized tax expense (benefit)		(1,340	)		438			(1,162	)
Deferred tax credits		(145	)		(169	)		(113	)
Deferred investment tax credits		(341	)		(298	)		(305	)
Total income tax expense	$	48,866		$	40,495		$	20,977

The components of deferred income tax at Dec. 31 were:

(Thousands of Dollars)	2010			2009			2008
Deferred tax expense excluding items below	$	25,318		$	31,740		$	5,837
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities		90			726			2,830
Endorsement split-dollar life insurance - new accounting guidance		-			-			9
Tax benefit allocated to other comprehensive income		(96	)		(2,093	)		(253	)
Deferred tax expense	$	25,312		$	30,373		$	8,423

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The components of net deferred tax liability (current and noncurrent portions) at Dec. 31 were:

(Thousands of Dollars)	2010		2009
Deferred tax liabilities:
Difference between book and tax bases of property	$	483,998	$	466,009
Employee benefits		53,505		53,047
Other		20,614		16,289
Total deferred tax liabilities	$	558,117	$	535,345

Deferred tax assets:
Unbilled revenue - fuel costs	$	11,051	$	10,575
Regulatory liabilities		9,506		485
NOL carryforward		4,482		3,393
Deferred fuel costs		3,668		10,366
Rate refund		2,248		9,605
Bad debts		1,835		1,589
Other		3,174		2,497
Total deferred tax assets	$	35,964	$	38,510
Net deferred tax liability	$	522,153	$	496,835

7. 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. Pension and other postretirement benefit disclosures below generally represent Xcel Energy consolidated information unless specifically identified as being attributable to SPS. Consistent with the process for rate recovery of pension and postretirement benefits for its employees, SPS accounts for its participation in, and related costs of, pension and other postretirement benefit plans sponsored by Xcel Energy (multiple employer plans). SPS is responsible for its share of cash contributions, plan costs and obligations and is entitled to its share of plan assets; accordingly, SPS accounts for its pro rata share of these plans, including pension expense and contributions, resulting in accounting consistent with that of a single employer plan exclusively for SPS employees.

Xcel Energy, which includes SPS, offers various benefit plans to its employees. At Dec. 31, 2010, SPS had 804 bargaining employees covered under a collective-bargaining agreement, which expires in October 2011.

Effective Jan. 1, 2009, Xcel Energy and SPS adopted new guidance on employers’ disclosures about pension and postretirement benefit plan assets. The new guidance expands employers’ disclosure requirements for benefit plan assets, including investment policies and strategies, major categories of plan assets, and information regarding fair value measurements consistent with the disclosures for entities’ recurring fair value measurements.

The fair value measurements accounting guidance establishes a hierarchal framework for disclosing the observability of the inputs utilized in measuring fair value. The three Levels defined by the hierarchy and examples of each Level are as follows:

Level 1 — Quoted prices are available in active markets for identical assets as of the reporting date. The types of assets included in Level 1 are highly liquid and actively traded instruments with quoted prices, such as common stocks listed by the New York Stock Exchange.

Level 2 — Pricing inputs are other than quoted prices in active markets, but are either directly or indirectly observable as of the reporting date. The types of assets included in Level 2 are typically either comparable to actively traded securities or contracts or priced with models using highly observable inputs, such as corporate bonds with pricing based on market interest rate curves and recent trades of similarly rated securities.

Level 3 — Significant inputs to pricing have little or no observability as of the reporting date. The types of assets included in Level 3 are those with inputs requiring significant management judgment or estimation, such as asset and mortgage backed securities, for which subjective risk-based adjustments to estimated yield and forecasted prepayments are significant inputs.

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Pension Benefits

Xcel Energy, which includes SPS, has several noncontributory, defined benefit pension plans that cover almost all employees. Benefits are based on a combination of years of service, the employee’s average pay and social security benefits. Xcel Energy’s and SPS’ policy is to fully fund into an external trust the actuarially determined pension costs recognized for ratemaking and financial reporting purposes, subject to the limitations of applicable employee benefit and tax laws.

Xcel Energy and SPS base investment-return assumption on expected long-term performance for each of the investment types included in the pension asset portfolio and consider the actual historical returns achieved by the asset portfolio over the past 20-year or longer period, as well as the long-term return levels projected and recommended by investment experts. The historical weighted average annual return for the past 20 years for the portfolio of pension investments is 9.72 percent, which is greater than the current assumption level. The pension cost determination assumes a forecasted mix of investment types over the long-term. Investment returns in 2010 were above the assumed level of 7.79 percent. Investment returns in 2009 were above the assumed level of 8.50 percent while returns in 2008 were below the assumed level of 8.75 percent. Xcel Energy and SPS continually review pension assumptions. In 2011, Xcel Energy will use an investment-return assumption of 7.50 percent.

The assets are invested in a portfolio according to Xcel Energy’s and SPS’ return, liquidity and diversification objectives to provide a source of funding for plan obligations and minimize the necessity of contributions to the plan, within appropriate levels of risk. The principal mechanism for achieving these objectives is the allocation of assets to selected asset classes, given the long-term risk, return, and liquidity characteristics of each particular asset class. There were no significant concentrations of risk in any particular industry, index, or entity; however, as we have experienced in recent years, unusual market volatility can impact even well-diversified portfolios and significantly affect the return levels achieved by pension assets in any year.

The following table presents the target pension asset allocation for 2010 and 2009:

	2010			2009
Domestic and international equity securities		24	%	24	%
Long-duration fixed income securities		41		34
Short-to-intermediate term fixed income securities		11		19
Alternative investments		17		18
Cash		7		5
Total		100	%	100	%

In 2009, Xcel Energy and SPS engaged J.P. Morgan’s Pension Advisory Group to evaluate the allocation of the total assets in the master pension trust, taking into consideration the funded status of each individual pension plan. The ongoing investment strategy is based on plan-specific investment recommendations that seek to minimize potential investment and interest rate risk as a plan’s funded status increases over time. The investment recommendations result in a greater percentage of short-to-intermediate term and long-duration fixed income securities being allocated to specific plans having relatively higher funded status ratios, and a greater percentage of growth assets being allocated to plans having relatively lower funded status ratios. The aggregate asset allocation presented in the table above for the master pension trust results from the plan-specific strategies.

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Pension Plan Assets

The following tables present, for each of the fair value hierarchy levels, pension plan assets that are measured at fair value as of Dec. 31, 2010 and 2009:

	Dec. 31, 2010
(Thousands of Dollars)	Level 1		Level 2			Level 3		Total
Cash equivalents	$	-	$	109,027		$	-	$	109,027
Short-term investments		122,643		26,683			-		149,326
Derivatives		-		8,140			-		8,140
Government securities		-		117,522			-		117,522
Corporate bonds		-		641,807			-		641,807
Asset-backed securities		-		-			26,986		26,986
Mortgage-backed securities		-		-			113,418		113,418
Common stock		117,899		-			-		117,899
Private equity investments		-		-			122,223		122,223
Commingled equity and bond funds		-		1,152,386			-		1,152,386
Real estate		-		-			73,701		73,701
Securities lending collateral obligation and other		-		(91,727	)		-		(91,727	)
Total	$	240,542	$	1,963,838		$	336,328	$	2,540,708

	Dec. 31, 2009
(Thousands of Dollars)	Level 1		Level 2			Level 3		Total
Cash equivalents	$	-	$	221,971		$	-	$	221,971
Short-term investments		-		324,683			-		324,683
Derivatives		-		11,606			-		11,606
Government securities		-		94,949			-		94,949
Corporate bonds		-		522,403			-		522,403
Asset-backed securities		-		-			47,825		47,825
Mortgage-backed securities		-		-			144,006		144,006
Common stock		89,260		-			-		89,260
Private equity investments		-		-			82,098		82,098
Commingled equity and bond funds		-		1,014,072			-		1,014,072
Real estate		-		-			66,704		66,704
Securities lending collateral obligation and other		-		(170,251	)		-		(170,251	)
Total	$	89,260	$	2,019,433		$	340,633	$	2,449,326

The following tables present the changes in Level 3 pension plan assets for the years ended Dec. 31, 2010 and 2009:

(Thousands of Dollars)	Jan. 1, 2010		Realized and Unrealized Gains (Losses)			Purchases, Issuances, and Settlements, net			Dec. 31, 2010
Asset-backed securities	$	47,825	$	(3,678	)	$	(17,161	)	$	26,986
Mortgage-backed securities		144,006		(5,376	)		(25,212	)		113,418
Real estate		66,704		7,100			(103	)		73,701
Private equity investments		82,098		(1,032	)		41,157			122,223
Total	$	340,633	$	(2,986	)	$	(1,319	)	$	336,328

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(Thousands of Dollars)	Jan. 1, 2009		Realized and Unrealized Gains (Losses)			Purchases, Issuances, and Settlements, net			Dec. 31, 2009
Asset-backed securities	$	77,398	$	48,285		$	(77,858	)	$	47,825
Mortgage-backed securities		166,610		103,470			(126,074	)		144,006
Real estate		109,289		(43,207	)		622			66,704
Private equity investments		81,034		(5,682	)		6,746			82,098
Total	$	434,331	$	102,866		$	(196,564	)	$	340,633

Benefit Obligations — A comparison of the actuarially computed pension benefit obligation and plan assets, on a combined basis, is presented in the following table:

(Thousands of Dollars)	2010			2009
Accumulated Benefit Obligation at Dec. 31	$	2,865,845		$	2,676,174

Change in Projected Benefit Obligation:
Obligation at Jan. 1	$	2,829,631		$	2,598,032
Service cost		73,147			65,461
Interest cost		165,010			169,790
Plan amendments		18,739			(35,341	)
Actuarial loss		169,203			223,122
Benefit payments		(225,438	)		(191,433	)
Obligation at Dec. 31	$	3,030,292		$	2,829,631

Change in Fair Value of Plan Assets:
Fair value of plan assets at Jan. 1	$	2,449,326		$	2,185,203
Actual return on plan assets		282,688			255,556
Employer contributions		34,132			200,000
Benefit payments		(225,438	)		(191,433	)
Fair value of plan assets at Dec. 31	$	2,540,708		$	2,449,326

Funded Status of Plans at Dec. 31:
Funded status (a)	$	(489,584	)	$	(380,305	)

SPS Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:
Net loss	$	207,981		$	198,711
Prior service cost		3,906			5,410
Total	$	211,887		$	204,121

Amounts Related to the Funded Status of the Plans Have Been Recorded as Follows Based Upon Expected Recovery in Rates:
Regulatory assets	$	211,887		$	204,121

SPS accrued benefit liability recorded		33,166			19,607

Measurement date	Dec. 31, 2010			Dec. 31, 2009

Significant Assumptions Used to Measure Benefit Obligations:
Discount rate for year-end valuation		5.50	%		6.00	%
Expected average long-term increase in compensation level		4.00			4.00
Mortality table	RP 2000			RP 2000

(a)	Amounts are recognized in noncurrent liabilities on Xcel Energy’s consolidated balance sheet.

Cash Flows — Cash funding requirements can be impacted by changes to actuarial assumptions, actual asset levels and other calculations prescribed by the funding requirements of income tax and other pension-related regulations. These regulations did not require cash funding for 2008 through 2010 for Xcel Energy’s pension plans and are not expected to require cash funding in 2011.

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Xcel Energy made total pension contributions of $34 million and $200 million during 2010 and 2009, respectively.

Voluntary contributions were made to the Xcel Energy Pension Plan of $34 million in 2010.

Voluntary contributions were made to the PSCo Bargaining Pension Plan of $173 million in 2009.

Voluntary contributions were made to the NCE Non-Bargaining Pension Plan of $27 million in 2009.

Voluntary contributions were made across three of Xcel Energy’s pension plans for $134 million in January 2011. The contribution raised the overall funded status from 84 percent at Dec. 31, 2010 to 88 percent with all other pension assumptions remaining constant.

Pension funding contributions for 2012, which will be dependent on several factors including, realized asset performance, future discount rate, IRS and legislative initiatives as well as other actuarial assumptions, are estimated to range between $150 million to $175 million.

Plan Amendments — The 2010 increase of the projected benefit obligation for plan amendments is due to a change in the discount rate basis for lump sum conversion of annuities for participants in the Xcel Energy Pension Plan.

Benefit Costs — The components of net periodic pension cost (credit) are:

(Thousands of Dollars)	2010			2009			2008
Service cost	$	73,147		$	65,461		$	62,698
Interest cost		165,010			169,790			167,881
Expected return on plan assets		(232,318	)		(256,538	)		(274,338	)
Amortization of prior service cost		20,657			24,618			20,584
Amortization of net loss		48,315			12,455			11,156
Net periodic pension cost (credit)	$	74,811		$	15,786		$	(12,019	)

SPS:
Net periodic pension cost (credit)	$	5,793		$	(6,644	)	$	(10,739	)

Significant Assumptions Used to Measure Costs:
Discount rate		6.00	%		6.75	%		6.25	%
Expected average long-term increase in compensation level		4.00			4.00			4.00
Expected average long-term increase in compensation level		7.79			8.50			8.75

Pension costs include an expected return impact for the current year that may differ from actual investment performance in the plan. The return assumption used for 2011 pension cost calculations will be 7.50 percent. The cost calculation uses a market-related valuation of pension assets. Xcel Energy, including SPS, uses a calculated value method to determine the market-related value of the plan assets. The market-related value begins with the fair market value of assets as of the beginning of the year. The market-related value is determined by adjusting the fair market value of assets to reflect the investment gains and losses (the difference between the actual investment return and the expected investment return on the market-related value) during each of the previous five years at the rate of 20 percent per year.

Xcel Energy, which includes SPS, also maintains noncontributory, defined benefit supplemental retirement income plans for certain qualifying executive personnel. Benefits for these unfunded plans are paid out of operating cash flows.

Defined Contribution Plans

Xcel Energy, including SPS, maintains 401(k) and other defined contribution plans that cover substantially all employees. The contributions for SPS were approximately $2.0 million in 2010, $1.4 million in 2009 and $1.2 million in 2008.

Postretirement Health Care Benefits

Xcel Energy, which includes SPS, has a contributory health and welfare benefit plan that provides health care and death benefits to most retirees. Employees of the former NCE who retired in 2002 continue to receive employer-subsidized health care benefits. Nonbargaining employees of the former NCE, who retired after June 30, 2003, are eligible to participate in the health care program with no employer subsidy.

In 1993, Xcel Energy and SPS adopted accounting guidance regarding other non-pension postretirement benefits and elected to amortize the unrecognized APBO on a straight-line basis over 20 years. Regulatory agencies for nearly all retail and wholesale utility customers have allowed rate recovery of accrued postretirement benefit costs under the new guidance.

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Plan Assets — Certain state agencies that regulate Xcel Energy’s utility subsidiaries also have issued guidelines related to the funding of postretirement benefit costs. SPS is required to fund postretirement benefit costs for Texas and New Mexico jurisdictional amounts collected in rates. Also, a portion of the assets contributed on behalf of nonbargaining retirees has been funded into a sub-account of the Xcel Energy pension plans. These assets are invested in a manner consistent with the investment strategy for the pension plan.

Xcel Energy and SPS base investment-return assumption for the postretirement health care fund assets on expected long-term performance for each of the investment types included in the asset portfolio. The assets are invested in a portfolio according to Xcel Energy’s and SPS’ return, liquidity and diversification objectives to provide a source of funding for plan obligations and minimize the necessity of contributions to the plan, within appropriate levels of risk. The principal mechanism for achieving these objectives is the allocation of assets to selected asset classes, given the long-term risk, return, and liquidity characteristics of each particular asset class. There were no significant concentrations of risk in any particular industry, index, or entity. Investment-return volatility is not considered to be a material factor in postretirement health care costs.

The following tables present, for each of the fair value hierarchy levels, postretirement benefit plan assets that are measured at fair value as of Dec. 31, 2010 and 2009:

	Dec. 31, 2010
(Thousands of Dollars)	Level 1		Level 2		Level 3		Total
Cash equivalent	$	72,573	$	76,352	$	-	$	148,925
Derivatives		-		13,632		-		13,632
Government securities		-		3,402		-		3,402
Corporate bonds		-		70,752		-		70,752
Asset-backed securities		-		-		2,585		2,585
Mortgage-backed securities		-		-		19,212		19,212
Preferred stock		-		507		-		507
Commingled equity and bond funds		-		102,962		-		102,962
Securities lending collateral obligation and other		-		70,253		-		70,253
Total	$	72,573	$	337,860	$	21,797	$	432,230

	Dec. 31, 2009
(Thousands of Dollars)	Level 1		Level 2		Level 3		Total
Cash equivalents	$	-	$	165,291	$	-	$	165,291
Short-term investments		-		2,226		-		2,226
Derivatives		-		5,937		-		5,937
Government securities		-		1,538		-		1,538
Corporate bonds		-		60,416		-		60,416
Asset-backed securities		-		-		8,293		8,293
Mortgage-backed securities		-		-		47,078		47,078
Preferred stock		-		540		-		540
Commingled equity and bond funds		-		89,296		-		89,296
Securities lending collateral obligation and other		-		4,074		-		4,074
Total	$	-	$	329,318	$	55,371	$	384,689

The following tables present the changes in Level 3 postretirement benefit plan assets for the year ended Dec. 31, 2010:

(Thousands of Dollars)	Jan. 1, 2010		Realized and Unrealized Gains		Purchases, Issuances, and Settlements, net			Dec. 31, 2010
Asset-backed securities	$	8,293	$	1,814	$	(7,522	)	$	2,585
Mortgage-backed securities		47,078		14,715		(42,581	)		19,212

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(Thousands of Dollars)	Jan. 1, 2009		Realized and Unrealized Gains		Purchases, Issuances, and Settlements, net			Dec. 31, 2009
Asset-backed securities	$	8,705	$	1,029	$	(1,441	)	$	8,293
Mortgage-backed securities		69,988		3,022		(25,932	)		47,078

Benefit Obligations — A comparison of the actuarially computed benefit obligation and plan assets, on a combined basis, is presented in the following table:

(Thousands of Dollars)	2010			2009
Change in Projected Benefit Obligation:
Obligation at Jan. 1	$	728,902		$	794,597
Service cost		4,006			4,665
Interest cost		42,780			50,412
Medicare subsidy reimbursements		5,423			3,226
Plan amendments		-			(27,407	)
Plan participants’ contributions		14,315			13,786
Actuarial loss (gain)		68,126			(47,446	)
Benefit payments		(68,647	)		(62,931	)
Obligation at Dec. 31	$	794,905		$	728,902

Change in Fair Value of Plan Assets:
Fair value of plan assets at Jan. 1	$	384,689		$	299,566
Actual return on plan assets		53,430			72,101
Plan participants’ contributions		14,315			13,786
Employer contributions		48,443			62,167
Benefit payments.		(68,647	)		(62,931	)
Fair value of plan assets at Dec. 31	$	432,230		$	384,689

Funded Status of Plans at Dec. 31:
Funded status	$	(362,675	)	$	(344,213	)
Current liabilities		(5,392	)		(2,240	)
Noncurrent liabilities		(357,283	)		(341,973	)
Net postretirement amounts recognized on consolidated balance sheets	$	(362,675	)	$	(344,213	)

SPS Amounts Not Yet Recognized as Components of Net Periodic Benefit Credit:
Net gain	$	(9,455	)	$	(6,914	)
Prior service credit		(182	)		(233	)
Transition obligations		3,214			4,883
Total	$	(6,423	)	$	(2,264	)

Amounts Related to the Funded Status of the Plans Have Been Recorded as Follows Based Upon Expected Recovery in Rates:
Regulatory assets and liabilities	$	(6,423	)	$	(2,264	)

SPS accrued benefit liability recorded		10,636			14,590

Measurement date	Dec. 31, 2010			Dec. 31, 2009

Significant Assumptions Used to Measure Benefit Obligations:
Discount rate for year-end valuation		5.50	%		6.00	%
Mortality table	RP 2000			RP 2000
Health care costs trend rate - inital		6.50	%		6.80	%

Effective Dec. 31, 2010, the ultimate trend assumption remained unchanged at 5.0 percent. The period until the ultimate rate is reached increased from three years to eight years. Xcel Energy bases its medical trend assumption on the long-term cost inflation expected in the health care market, considering the levels projected and recommended by industry experts, as well as recent actual medical cost increases experienced by Xcel Energy’s retiree medical plan.

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A 1-percent change in the assumed health care cost trend rate would have the following effects on SPS:

	One Percentage Point
(Thousands of Dollars)	Increase			Decrease
APBO		$	98,812		$	(76,175	)
Service and interest components			5,006			(4,193	)

Cash Flows — The postretirement health care plans have no funding requirements under income tax and other retirement-related regulations other than fulfilling benefit payment obligations, when claims are presented and approved under the plans. Additional cash funding requirements are prescribed by certain state and federal rate regulatory authorities, as discussed previously. Xcel Energy, which includes SPS, contributed $48.4 million during 2010 and $62.2 million during 2009 and expects to contribute approximately $40.5 million during 2011.

Plan Amendments — No amendments occurred during 2010 to the Xcel Energy health and welfare benefit plan.

Benefit Costs — The components of net periodic postretirement benefit cost are:

(Thousands of Dollars)	2010			2009			2008
Service cost	$	4,006		$	4,665		$	5,350
Interest cost		42,780			50,412			51,047
Expected return on plan assets		(28,529	)		(22,775	)		(31,851	)
Amortization of transition obligation		14,444			14,444			14,577
Amortization of prior service cost		(4,932	)		(2,726	)		(2,175	)
Amortization of net loss		11,643			19,329			11,498
Net periodic postretirement benefit cost	$	39,412		$	63,349		$	48,446

SPS:
Net periodic postretirement benefit cost recognized	$	3,601		$	5,000		$	3,484

Significant Assumptions Used to Measure Costs:
Discount rate		6.00	%		6.75	%		6.25	%
Expected average long-term rate of return on assets (before tax)		7.50			7.50			7.50

Projected Benefit Payments — The following table lists the projected benefit payments for the pension and postretirement benefit plans:

(Thousands of Dollars)	Projected Pension Benefit Payments		Gross Projected Postretirement Health Care Benefit Payments		Expected Medicare Part D Subsidies		Net Projected Postretirement Health Care Benefit Payments
2011	$	254,426	$	59,752	$	4,770	$	54,982
2012		247,156		60,230		5,126		55,104
2013		249,908		60,607		5,475		55,132
2014		257,886		61,833		5,773		56,060
2015		259,978		63,184		6,061		57,123
2016-2020		1,338,658		325,154		34,115		291,039

8. Other Income, Net

Other income (expense), net for the years ended Dec. 31 consisted of the following:

(Thousands of Dollars)	2010			2009			2008
Interest income	$	250		$	671		$	4,874
Other nonoperating income		57			68			330
Insurance policy (expenses) income		(280	)		(475	)		673
Other nonoperating expenses		-			-			(48	)
Other income, net	$	27		$	264		$	5,829

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9. Derivative Instruments and Fair Value Measurements

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

Short-Term Wholesale and Commodity Trading Risk — SPS conducts an immaterial amount of short-term wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy and energy related instruments. SPS’ risk management policy allows management to conduct these activities within guidelines and limitations as approved by its risk management committee, which is made up of management personnel not directly involved in the activities governed by the policy.

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

At Dec. 31, 2010, accumulated other comprehensive losses related to interest rate derivatives included $0.2 million of net losses expected to be reclassified into earnings during the next 12 months as the related hedged interest rate transactions impact earnings.

Accumulated other comprehensive losses related to interest rate derivatives reclassified into earnings during the year ended Dec. 31, 2010 and Dec. 31, 2009 were $0.3 million and 5.8 million, respectively.

During the fourth quarter of 2009, SPS settled a $25 million notional value interest rate swap. The interest rate swap was not designated as a hedging instrument, and as such, $2.5 million of changes in fair value of the swap were recorded to earnings for the swap during the year ended Dec. 31, 2009.

Commodity Derivatives — SPS may enter into derivative instruments to manage variability of future cash flows from changes in commodity prices in its electric utility operations. This could include the purchase or sale of energy or energy-related products. At Dec. 31, 2010 and Dec. 31, 2009, SPS held no commodity derivatives. Changes in the fair value of non-trading commodity derivative instruments are recorded in other comprehensive income or deferred as a regulatory asset or liability. The classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms.

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

Dec. 31, 2010

Dec. 31, 2009

Derivative

Instruments -

(Thousands of Dollars)

Assets

Liabilities

Assets

Liabilities

Long-term purchased power agreements

72,626

48,592

76,551

52,242

In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, SPS began recording several long-term purchased power agreements at fair value due to accounting requirements related to underlying price adjustments. As these purchases are recovered through normal regulatory recovery mechanisms in the respective jurisdictions, the changes in fair value for these contracts were offset by regulatory assets and liabilities. During 2006, SPS qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.

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

(Thousands of Dollars)	2010			2009			2008
Accumulated other comprehensive loss related to cash flow hedges at Jan 1	$	(1,847	)	$	(5,559	)	$	(6,005	)
After-tax net unrealized gains related to derivatives accounted for as hedges		-			-			71
After-tax net realized losses on derivative transactions reclassified into earnings		172			3,712			375
Accumulated other comprehensive loss related to cash flow hedges at Dec. 31	$	(1,675	)	$	(1,847	)	$	(5,559	)

Fair Value Measurements

SPS had no derivative instruments measured at fair value on a recurring basis as of Dec. 31, 2010 and Dec. 31, 2009.

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10. Financial Instruments

The estimated Dec. 31 fair values of SPS’ recorded financial instruments are as follows:

	2010				2009
(Thousands of Dollars)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Other investments	$	246	$	246	$	263	$	263
Long-term debt, including current portion		897,767		989,789		922,447		977,029

The fair values of cash and cash equivalents, notes and accounts receivable and notes and accounts payable are not materially

different from their carrying amounts. The fair value of SPS’ long-term investments are estimated based on quoted market prices for those or similar investments. The fair value of SPS’ long-term debt is estimated based on the quoted market prices for the same or similar issues or the current rates for debt of the same remaining maturities and credit quality.

The fair value estimates presented are based on information available to management as of Dec. 31, 2010 and 2009. These fair value estimates have not been comprehensively revalued for purposes of these financial statements since that date and current estimates of fair value may differ significantly.

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

(Millions of Dollars)

Guarantee Amount

Current Exposure

Term or Expiration Date

Triggering Event Requiring Performance

Assets Held as Collateral

Guarantee of indemnification obligations of Lubbock under an asset purchase agreement

(a)

Continuing

(a)

N/A

(a) SPS has provided indemnification to Lubbock for losses arising out of any breach of the representations, warranties and covenants under the related asset purchase agreement and for losses arising out of certain other matters, including pre-closing unknown liabilities. The indemnification provisions are capped at the purchase price, $87 million, in the aggregate. As of Dec. 31, 2010, no claims have been made. The indemnification provisions for most representations and warranties expire 12 months after the closing date. Certain representations and warranties, including those having to do with transaction authorization survive indefinitely. The indemnification for covenants survives until the applicable covenant is performed. See Note 17 to the financial statements for further discussion.

Letters of Credit

SPS uses letters of credit, generally with terms of one year, to provide financial guarantees for certain operating obligations. At Dec. 31, 2010, there were no letters of credit outstanding. At Dec. 31, 2009, there were $10.0 million of letters of credit outstanding. The contract amounts of these letters of credit approximate their fair values and are subject to fees determined in the marketplace.

11. Rate Matters

Pending and Recently Concluded Regulatory Proceedings — PUCT

Base Rate

Texas Retail Base Rate Case — In May 2010, SPS filed an electric rate case in Texas seeking an annual base rate increase of approximately $71.5 million inclusive of franchise fees. On a net basis, the request seeks to increase customer bills by approximately $53.4 million or 7 percent. The rate filing is based on a 2009 test year adjusted for known and measurable changes, a requested ROE of 11.35 percent, an electric rate base of $1.031 billion and an equity ratio of 51.0 percent. The filing with the PUCT also includes a request to reconcile SPS’ fuel and purchased power costs for calendar years 2008 and 2009. As of Dec. 31, 2009, SPS had a fuel cost under-recovery of approximately $3.3 million.

In November 2010, SPS filed an update to the cost of service to reflect the impact on Texas retail rates, primarily resulting from its sale of Lubbock facilities. The total request was reduced to approximately $63.7 million and the net request $47.6 million.

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On Feb. 11, 2011, the parties reached an unopposed settlement to resolve all issues in the case. Effective Feb. 16, 2011 base rates increased by $39.4 million, of which $16.9 is associated with the transfer of two riders, the TCRF and Power Cost Recovery Factor into base rates and a $22.5 million traditional base rate increase. In addition, SPS is allowed to defer up to $2.3 million of pension and benefit costs and $1.6 million of renewable energy credits that had been included in SPS’ base rate request.

Effective Jan. 1, 2012, the settlement provides for SPS to increase base rates by $13.1 million and allows SPS to seek an energy efficiency cost recovery factor rider for $2.9 million that if approved would result in an effective rate increase of $16.0 million. SPS plans to make its filing for the rider by May 1, 2011 pursuant to a recent PUCT order. In addition, SPS is allowed to track and defer up to $4.3 million of pension and benefit costs above the test year levels as well as $1.6 million of renewable energy credits, as described above.

SPS agreed not to file another rate case until Sept.15, 2012. In addition, SPS cannot file a TCRF until 2013, and if SPS files a TCRF application before the effective date of rates in its next rate case, it must reduce the calculated TCRF revenue requirement by $12.2 million.

Interim rates became effective on Feb. 16, 2011, subject to refund pending PUCT approval of the settlement. PUCT approval of the settlement would result in no refund of interim rates. The PUCT is expected to consider the final order during the first half of 2011.

Pending and Recently Concluded Regulatory Proceedings — FERC

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

In April 2008, the FERC issued its order on the complaint applied to the remaining non-settling parties. In July 2008, SPS submitted its compliance report to the FERC and calculated the base rate refund for the 18-month period to be $6.1 million and the fuel refund to be $4.4 million. Several wholesale customers protested these calculations. The status of various settlements and the applicable regulatory approvals are discussed below. At this time, PNM, which filed a separate complaint, is the only party that has not settled. As of Dec. 31, 2010, SPS has accrued an amount it believes is sufficient to cover the estimated refund obligation related to the PNM complaint.

Golden Spread Complaint Settlement — SPS reached a settlement with Golden Spread (which included Lyntegar Electric) and Occidental in December 2007 regarding base rate and fuel issues raised in the complaint described above as well as a subsequent rate proceeding. The FERC approved the settlement in April 2008. The PUCT and NMPRC approvals were obtained in the first quarter of 2010 eliminating the potential contingent payments by SPS resulting from an adverse cost assignment decision or a failure to obtain state approvals.

New Mexico Cooperatives’ Complaint Settlement — In June 2010, the FERC approved the settlement with Farmers’ Electric Cooperative of New Mexico, Lea County Electric Cooperative, Central Valley Electric Cooperative and Roosevelt County Electric Cooperative, and Occidental. The settlement resolves all issues arising from the complaint docket and implements a replacement contract with a formula production rate at 10.5 percent ROE and extended the term of its requirements sale to the four wholesale customers.

The four wholesale customers must reduce their power purchases by 90 to 100 MW in 2012, and implement staged reductions in system average cost power purchases through the term of the agreement, which terminates in May 2026. The settlement made the replacement contract contingent on certain state approvals, which were obtained by SPS. In the event that all state regulatory approvals had not been received, the settlement included a one time contingent payment of $12 million by SPS to these wholesale customers.

These wholesale customers agreed to hold SPS harmless from any future adverse regulatory treatment regarding the proposed wholesale power sale. As a result of the FERC approval of the settlement and resolution of the complaint with the New Mexico cooperatives, SPS released previously established reserves of $11.5 million in the second quarter of 2010.

The New Mexico parties and NMPRC staff filed a stipulation to resolve the NMPRC proceeding. The NMPRC issued a final order approving the stipulation in August 2010. The PUCT approved the settlement replacement arrangement in September 2010.

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Cap Rock Complaint Settlement — In July 2010, SPS and Cap Rock filed a settlement agreement with the FERC. Cap Rock agrees that its production base rates will be converted to a formula rate design. In December 2010, the FERC approved the settlement. Pursuant to the settlement, SPS released previously established reserves of $3.3 million in the fourth quarter of 2010 and paid Cap Rock $1 million.

12. Commitments and Contingent Liabilities

Capital Commitments — As of Dec. 31, 2010, the estimated cost of capital expenditure programs of SPS is approximately $300 million in 2011, $280 million in 2012 and $450 million in 2013.

The capital expenditure programs of SPS are subject to continuing review and modification. Actual utility construction expenditures may vary from the estimates due to changes in projected electric load growth, regulatory decisions, legislative initiatives, reserve margins, the availability of purchased power, alternative plans for meeting SPS’ long-term energy needs, compliance with future requirements and RPS to install emission-control equipment and merger, acquisition and divestiture opportunities to support corporate strategies may impact actual capital requirements.

Fuel Contracts — SPS has contracts providing for the purchase and delivery of a significant portion of its current coal and natural gas requirements. These contracts expire in various years between 2011 and 2033. SPS may be required to pay additional amounts depending on actual quantities shipped under these agreements. The potential risk of loss, in the form of increased costs from market price changes in fuel, is mitigated through the cost-rate adjustment mechanisms, which provide for pass-through of most fuel, storage and transportation costs to customers.

The estimated minimum purchases for SPS under these contracts as of Dec. 31, 2010, is as follows:

(Millions of Dollars)
Coal	$	785.1
Natural gas supply		27.8
Natural gas storage and transportation		233.4

Purchased Power Agreements — SPS has entered into agreements with other utilities and energy suppliers for purchased power to meet system load and energy requirements, replace generation from company-owned units under maintenance or during outages, and meet operating reserve obligations.

SPS has various pay-for-performance contracts with expiration dates through the year 2033. In general, these contracts provide for energy payments based on actual power taken under the contracts as well as capacity payments. Capacity payments are typically contingent on the independent power producing entity meeting certain contract obligations, including plant availability requirements. Certain contractual payments are adjusted based on market indices; however, the effects of price adjustments are mitigated through purchased energy cost recovery mechanisms.

Included in electric fuel and purchased power expenses for purchase power agreements accounted for as executory contracts were payments for capacity of $42.0 million, $44.3 million, and $45.1 million in 2010, 2009 and 2008, respectively. At Dec. 31, 2010, the estimated future payments for capacity that SPS was obligated to purchase, subject to availability, are as follows:

(Millions of Dollars)
2011	$	38.2
2012		36.9
2013		37.6
2014		38.3
2015		39.1
2016 and thereafter		194.8
Total	$	384.9

Leases — SPS leases a variety of equipment and facilities used in the normal course of business, which are accounted for as operating leases. Total expenses under operating lease obligations was approximately $56.6 million, $54.6 million and $18.6 million for 2010, 2009 and 2008, respectively. These expenses include payments for capacity recorded to electric fuel and purchased power expenses for purchase power agreements accounted for as operating leases of $52.8 million, $50.3 million and $14.2 million in 2010, 2009 and 2008, respectively.

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Included in the future commitments under operating leases are estimated future payments under purchase power agreements that have been accounted for as operating leases in accordance with the applicable guidance. Future commitments under operating leases are:

(Millions of Dollars)	Other Operating Leases		Purchased Power Agreement Operating Leases (a) (b)		Total Operating Leases
2011	$	3.0	$	50.2	$	53.2
2012		2.6		48.3		50.9
2013		2.4		44.4		46.8
2014		2.4		44.5		46.9
2015		2.5		44.4		46.9
Thereafter		14.3		788.4		802.7

(a)	Amounts not included in purchase power agreement estimated future payments above.

(b)	Purchase power agreement operating leases contractually expire through 2033.

Variable Interest Entities — Effective Jan. 1, 2010, SPS adopted new guidance on consolidation of variable interest entities. The guidance requires enterprises to consider the activities that most significantly impact an entity’s financial performance, and power to direct those activities, when determining whether an entity is a variable interest entity and whether an enterprise is a variable interest entity’s primary beneficiary.

Purchased Power Agreements — SPS purchases power from independent power producing entities that own natural gas fueled power plants. Under certain purchased power agreements with these entities, SPS is required to reimburse natural gas fuel costs, or to participate in tolling arrangements under which SPS procures the natural gas required to produce the energy that SPS purchases. These specific purchased power agreements have been determined by SPS to create variable interests in the independent power producing entities; therefore, certain independent power producing entities are variable interest entities.

SPS is not subject to risk of loss from the operations of these entities, and no significant financial support has been, or is in the future required to be provided other than contractual payments for energy and capacity set forth in purchased power agreements.

SPS has evaluated each of these variable interest entities for possible consolidation, including review of qualitative factors such as the length and terms of the contract, control over O&M, historical and estimated future fuel and electricity prices, and financing activities. SPS has concluded that these entities are not required to be consolidated in its financial statements because it does not have the power to direct the activities that most significantly impact the entities’ economic performance. As of Dec. 31, 2010 and Dec. 31, 2009, SPS had approximately 1,027 MW of capacity under long-term purchased power agreements with entities that have been determined to be variable interest entities.

Fuel Contracts — SPS purchases all of its coal requirements for its Harrington and Tolk electric generating stations from TUCO under contracts for those facilities that expire in 2016 and 2017, respectively. TUCO arranges for the purchase, receiving, transporting, unloading, handling, crushing, weighing, and delivery of coal to meet SPS’ requirements. TUCO is responsible for negotiating and administering contracts with coal suppliers, transporters and handlers.

No significant financial support has been, or is in the future, required to be provided to TUCO by SPS, other than contractual payments for delivered coal. However, the fuel contracts have been determined to create a variable interest in TUCO due to SPS’ reimbursement of certain fuel procurement costs, and therefore TUCO is a variable interest entity. SPS has concluded that it is not the primary beneficiary of TUCO because SPS does not have the power to direct the activities that most significantly impact TUCO’s economic performance.

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 PRPs and through the rate regulatory process. New and changing federal and state environmental mandates can also create added financial liabilities for SPS, which are normally recovered through the rate regulatory process. To the extent any costs are not recovered through the options listed above, SPS would be required to recognize an expense.

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Site Remediation — The Comprehensive Environmental Response, Compensation and Liability Act of 1980 and comparable state laws impose liability, without regarding the legality of the original conduct, on certain classes of persons responsible for the release of hazardous substances to the environment. SPS must pay all or a portion of the cost to remediate sites where past activities of SPS or other parties have caused environmental contamination. Environmental contingencies could arise from various situations, including third party sites, to which SPS is alleged to be a PRP that sent hazardous materials and wastes. At Dec. 31, 2010 and Dec. 31, 2009, the liability for the cost of remediating these sites was estimated to be $0.1 million.

Asbestos Removal — Some of SPS’ facilities contain asbestos. Most asbestos will remain undisturbed until the facilities that contain it are demolished or removed. SPS has recorded an estimate for final removal of the asbestos as an ARO. See additional discussion of AROs below. It may be necessary to remove some asbestos to perform maintenance or make improvements to other equipment. The cost of removing asbestos as part of other work is immaterial and is recorded as incurred as operating expenses for maintenance projects, capital expenditures for construction projects or removal costs for demolition projects.

Other Environmental Requirements

EPA GHG Endangerment Rulemaking — In December 2009, the EPA issued its “endangerment” finding that GHG emissions endanger public health and welfare and that emissions from motor vehicles contribute to the GHGs in the atmosphere. The EPA has promulgated permit requirements for GHGs for large new and modified stationary sources, such as power plants. These regulations became applicable in 2011. In December 2010, the EPA announced a settlement with several states and environmental groups to begin preparing regulations of emissions from both new and existing steam electric generating units, such as coal-fired power plants, under Section 111 of the CAA. The EPA plans to propose these regulations in July 2011 and finalize them in the first half of 2012.

CAIR — In 2005, the EPA issued the CAIR to further regulate SO2 and NOx emissions. The objective of CAIR is to cap emissions of SO2 and NOx in the eastern United States, including Texas. In 2008, the U.S. Court of Appeals for the District of Columbia vacated and remanded CAIR.

In July 2010, the EPA issued the proposed CATR, which would replace CAIR by requiring SO2 and NOx reductions in 31 states and the District of Columbia. The EPA is proposing to reduce these emissions through federal implementation plans for each affected state. The EPA’s preferred approach would set emission limits for each state and allow limited interstate emissions trading. As proposed, CATR will impact operations in Texas in the form of ozone season NOx emission allowances. SPS is analyzing the proposed rule to determine whether emission reductions are needed from facilities. Until CATR becomes final, SPS will continue activities to support CAIR compliance.

Under CAIR’s cap and trade structure, SPS can comply through capital investments in emission controls or purchase of emission allowances from other utilities making reductions on their systems. The remaining scheduled capital investments for NOx controls in the SPS region are estimated at $16.4 million. For 2010, the NOx allowance compliance costs were $0.5 million. Annual purchases of SO2 allowances are estimated to be up to $4.5 million each year, beginning in 2013, for phase I. If CATR is implemented as proposed then no SO2 allowances would be purchased since CATR replaces CAIR. SPS believes the cost of any required capital investment or allowance purchases will be recoverable from customers in rates.

CAMR — In 2005, the EPA issued the CAMR, which regulated mercury emissions from power plants. The TCEQ adopted by reference the EPA model program. In February 2008, the U.S. Court of Appeals for the District of Columbia vacated the CAMR, which impacted federal CAMR requirements, but not necessarily state-only mercury legislation and rules. The EPA has agreed to finalize Maximum Achievable Control Technology emission standards for all hazardous air pollutants from electric utility steam generating units by November 2011 to replace the CAMR. SPS anticipates that the EPA will require affected facilities to demonstrate compliance within three to five years. Costs associated with such requirements are uncertain at this time. At this time, Texas has not adopted any state-only mercury requirements.

Regional Haze Rules — In 2005, the EPA finalized amendments its regional haze rules, including provisions that require the installation and operation of emission controls, known as BART, for industrial facilities emitting air pollutants that reduce visibility in certain national parks and wilderness areas throughout the United States. Some of SPS’ generating facilities will be subject to BART requirements. Some of these facilities are located in regions where CAIR is currently effective. The TCEQ had determined that facilities may use CAIR as a substitute for BART for NOx and SO2.

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Proposed Coal Ash Regulation — Xcel Energy’s operations generate hazardous wastes that are subject to the Federal Resource Recovery and Conservation Act and comparable state laws that impose detailed requirements for handling, storage, treatment and disposal of hazardous waste. In June 2010, the EPA published a proposed rule seeking comment on whether to regulate coal combustion byproducts (often referred to as coal ash) as hazardous or nonhazardous waste. Coal ash is currently exempt from hazardous waste regulation. If the EPA ultimately issues a final rule under which coal ash is regulated as hazardous waste, Xcel Energy’s costs associated with the management and disposal of coal ash would significantly increase, and the beneficial reuse of coal ash would be negatively impacted. Xcel Energy submitted comments to the EPA on Nov. 19, 2010 indicating its support of the development of regulations to manage coal ash as a nonhazardous waste. The timing, scope and potential cost of any final rule that might be implemented are not determinable at this time.

Cunningham Compliance Order — In February 2010, SPS received a draft compliance order from the NMED for Cunningham Station. In the draft order, NMED alleges that Cunningham exceeded its permit limits for NOx and failed to report these exceedances as required by its permit. In September 2010, the NMED issued a final compliance order, that contained a penalty of $7.6 million. SPS requested an administrative hearing to contest the order. The administrative hearing has been scheduled for April 2011.

Asset Retirement Obligations

SPS records future plant removal obligations as a liability at fair value with a corresponding increase to the carrying values of the related long-lived assets in accordance with the applicable guidance. This liability will be increased over time by applying the interest method of accretion to the liability and the capitalized costs will be depreciated over the useful life of the related long-lived assets. The recording of the obligation for regulated operations has no income statement impact due to the deferral of the adjustments through the establishment of a regulatory asset.

Recorded ARO — AROs have been recorded for steam production and electric transmission and distribution. The steam production obligation includes asbestos and ash containment facilities. The asbestos recognition associated with the steam production includes certain plants at SPS. Generally, this asbestos abatement removal obligation originated in 1973 with the CAA applied to the demolition of buildings or removal of equipment containing asbestos that can become airborne on removal. AROs also have been recorded for SPS steam production related to ash-containment facilities such as bottom ash ponds, evaporation ponds and solid waste landfills. The origination date on the ARO recognition for ash-containment facilities at steam plants was the in-service date of various facilities.

An ARO was recognized for the removal of electric transmission and distribution equipment at SPS. The electric transmission and distribution ARO consists of many small potential obligations associated with PCBs, mineral oil, storage tanks, treated poles, lithium batteries, mercury and street lighting lamps. These electric assets have many in-service dates for which it is difficult to assign the obligation to a particular year. Therefore, the obligation was measured using an average service life.

A reconciliation of the beginning and ending aggregate carrying amounts of SPS’ AROs is shown in the table below for the 12 months ended Dec. 31, 2010 and Dec. 31, 2009:

(Thousands of Dollars)	Beginning Balance Jan. 1, 2010			Accretion			Revisions to Prior Estimates			Ending Balance Dec. 31, 2010 (a)
Steam production asbestos	$	18,596		$	1,272		$	92		$	19,960
Steam production ash containment		417			20			(92	)		345
Electric transmission and distribution		(256	)		(4	)		1,086			826
Total liability	$	18,757		$	1,288		$	1,086		$	21,131

(a)	There were no ARO liabilities recorded or liabilities settled during the 12 months ended Dec. 31, 2010 or Dec. 31, 2009.

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SPS revised ash-containment facilities, steam production and electric transmission and distribution asset retirement obligations due to revised estimates and end of life dates.

(Thousands of Dollars)	Beginning Balance Jan. 1, 2009		Accretion		Revisions to Prior Estimates			Ending Balance Dec. 31, 2009 (a)
Steam production asbestos	$	17,498	$	1,190	$	(92	)	$	18,596
Steam production ash containment		392		25		-			417
Electric transmission and distribution		13		1		(270	)		(256	)
Total liability	$	17,903	$	1,216	$	(362	)	$	18,757

(a)	There were no ARO liabilities recorded or liabilities settled during the 12 months ended Dec. 31, 2010 or Dec. 31, 2009.

SPS revised ash-containment facilities and electric transmission and distribution asset retirement obligations due to revised estimates and end of life dates.

Removal Costs — SPS records a regulatory liability for plant removal costs for generation, transmission and distribution facilities. Generally, the accrual of future non-ARO removal obligations is not required. However, long-standing ratemaking practices approved by applicable state and federal regulatory commissions have allowed provisions for such costs in historical depreciation rates. These removal costs have accumulated over a number of years based on varying rates as authorized by the appropriate regulatory entities. Given the long periods over which the amounts were accrued and the changing of rates through time, SPS has estimated the amount of removal costs accumulated through historic depreciation expense based on current factors used in the existing depreciation rates. Accordingly, the recorded amounts of estimated future removal costs are considered regulatory liabilities. Removal costs as of Dec. 31, 2010 and Dec. 31, 2009, were $88 million and $93 million, respectively.

Legal Contingencies

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

Environmental Litigation

State of Connecticut vs. Xcel Energy Inc. et al. — In 2004, the attorneys general of eight states and New York City, as well as several environmental groups, filed lawsuits in U.S. District Court in the Southern District of New York against five utilities, including Xcel Energy, the parent company of SPS, to force reductions in CO2 emissions. The other utilities include American Electric Power Co., Southern Co., Cinergy Corp. (merged into Duke Energy Corporation) and Tennessee Valley Authority. The lawsuits allege that CO2 emitted by each company is a public nuisance. The lawsuits do not demand monetary damages. Instead, the lawsuits ask the court to order each utility to cap and reduce its CO2 emissions. In September 2005, the court granted plaintiffs’ motion to dismiss on constitutional grounds. In August 2010, this decision was reversed by the Second Circuit and is currently on appeal before the United States Supreme Court. Oral arguments will be presented to the Supreme Court on April 19, 2011 and a decision is expected in the summer of 2011.

Comer vs. Xcel Energy Inc. et al. — In 2006, Xcel Energy, the parent company of SPS, received notice of a purported class action lawsuit filed in U.S. District Court in the Southern District of Mississippi. The lawsuit names more than 45 oil, chemical and utility companies, including Xcel Energy, as defendants and alleges that defendants’ CO2 emissions “were a proximate and direct cause of the increase in the destructive capacity of Hurricane Katrina.” Plaintiffs allege 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. In August 2007, the court dismissed the lawsuit in its entirety against all defendants on constitutional grounds. Plaintiffs’ subsequent appeals of this decision were unsuccessful, rendering the District Court’s dismissal the final determination.

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

Employment, Tort and Commercial Litigation

John Deere Wind Complaint — Presently, three lawsuits have been filed by John Deere Wind Energy subsidiaries (JD Wind) arising out of a dispute concerning SPS’ payments for energy produced from JD Wind projects. The first lawsuit was filed in June 2009 in Texas state district court against the PUCT. In this lawsuit JD Wind filed a petition seeking review of a May 2009 PUCT order denying JD Wind’s request for relief against SPS. The PUCT has denied all allegations contained in this petition. It is uncertain when this lawsuit will be concluded.

A second lawsuit was filed in December 2009 by JD Wind against the PUCT in U.S. district court. This lawsuit was filed shortly after a declaratory order issued by FERC stated that the PUCT’s May 2009 order (approving SPS’ payments to JD Wind) is not consistent with FERC’s regulations. In this lawsuit JD Wind seeks declaratory and injunctive relief against the PUCT. The U.S. District Court issued an order preventing this lawsuit from proceeding pending the outcome of the state court proceeding against the PUCT.

In January 2010 a third lawsuit was filed by JD Wind against SPS in Texas state district court related to payments made by SPS for energy produced from the JD Wind projects. This lawsuit seeks unspecified damages against SPS. It is uncertain when this lawsuit will conclude. No accrual has been recorded for this lawsuit nor is it expected that this proceeding will have a material adverse effect upon SPS’ financial statements.

13. Regulatory Assets and Liabilities

SPS’ financial statements are prepared in accordance with the applicable industry accounting guidance, as discussed in Note 1 to the financial statements. Under this guidance, regulatory assets and liabilities can be created for amounts that regulators may allow to be collected, or may require to be paid back to customers in future electric rates. Any portion of the business that is not rate regulated cannot establish regulatory assets and liabilities. If changes in the utility industry or the business of SPS no longer allow for the application of regulatory accounting guidance under GAAP, SPS would be required to recognize the write-off of regulatory assets and liabilities in its statement of income.

The components of regulatory assets and liabilities shown on the balance sheets of SPS at Dec. 31, 2010 and Dec. 31, 2009 are:

(Thousands of Dollars)	See Note		Remaining Amortization Period	Dec. 31, 2010				Dec. 31, 2009
Regulatory Assets				Current		Noncurrent		Current		Noncurrent
Recoverable electric energy costs		1	Less than one year	$	1,672	$	-	$	1,159	$	-
Pension and employee benefit obligations (a)		7	Various		9,407		203,513		6,789		196,181
AFUDC recorded in plant (b)		1	Plant lives		-		23,673		-		23,035
Net AROs (d)		12	Plant lives		-		18,882		-		17,496
Conservation programs (b)		1	One to ten years		5,201		12,371		673		14,524
Losses on reacquired debt		1	Term of related debt		1,249		7,092		1,308		8,341
Renewable and environmental initiative costs		12	One to four years		2,046		5,719		2,150		1,822
Deferred income tax adjustment		1	Typically plant lives		-		7,123		-		7,861
Other			Various		1,972		4,834		4,397		2,157
Total regulatory assets				$	21,547	$	283,207	$	16,476	$	271,417

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(Thousands of Dollars)	See Note		Remaining Amortization Period	Dec. 31, 2010					Dec. 31, 2009
Regulatory Liabilities				Current		Noncurrent			Current			Noncurrent
Deferred electric energy costs.		1		$	44,588		$	-		$	59,783		$	-
Plant removal costs		12			-			88,224			-			93,426
Contract valuation adjustments (c)		9			4,291			19,743			5,338			18,970
Gain from asset sales		17	Pending rate case		4,281			18,792			-			-
Other					37			8,193			-			1,346
Total regulatory liabilities				$	53,197		$	134,952		$	65,121		$	113,742

(a)	Includes the non-qualified pension plan.

(b)	Earns a return on investment in the ratemaking process. These amounts are amortized consistent with recovery in rates.

(c)	Includes the fair value of certain long-term PPAs used to meet energy capacity requirements.

(d)	Includes amounts recorded for future recovery of AROs.

14. Segments and Related Information

SPS has only one reportable segment. SPS is a wholly owned subsidiary of Xcel Energy and operates in the regulated electric utility industry providing wholesale and retail electric service in the states of Texas and New Mexico. Revenues from external customers were $1,613.0 million, $1,459.2 million and $1,992.8 million for the years ended Dec. 31, 2010, 2009 and 2008, respectively.

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

15. Related Party Transactions

Xcel Energy Services Inc. provides management, administrative and other services for the subsidiaries of Xcel Energy, including SPS. The services are provided and billed to each subsidiary in accordance with Service Agreements executed by each subsidiary. Costs are charged directly to the subsidiary which uses the service whenever possible and are allocated if they cannot be directly assigned.

Xcel Energy has established a utility money pool arrangement with the utility subsidiaries. See Note 4 for further discussion of this borrowing arrangement.

The table below contains significant affiliate transactions among the companies and related parties for the years ended Dec. 31:

(Thousands of Dollars)	2010		2009		2008
Operating revenues:
Electric	$	6,805	$	5,976	$	7,000
Operating expenses:
Purchased power		9,428		7,751		38,625
Other operating expenses — paid to Xcel Energy Services Inc		109,111		96,375		94,291
Interest expense		90		106		1,549
Interest income		25		495		291

Accounts receivable and payable with affiliates at Dec. 31 were:

	2010						2009
(Thousands of Dollars)	Accounts Receivable			Accounts Payable			Accounts Receivable			Accounts Payable
NSP-Minnesota		$	1,610		$	-		$	2,268		$	-
NSP-Wisconsin			-			2			29			-
PSCo			-			2,606			239			-
Other subsidiaries of Xcel Energy			-			21,917			2,561			14,625
		$	1,610		$	24,525		$	5,097		$	14,625

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16. Summarized Quarterly Financial Data (Unaudited)

Due to the seasonality of SPS’ electric sales, such interim results are not necessarily an appropriate base from which to project annual results. Summarized quarterly unaudited financial data is as follows:

	Quarter Ended
(Thousands of Dollars)	March 31, 2010			June 30, 2010			Sept. 30, 2010			Dec. 31, 2010
Operating revenues		$	381,482		$	398,449		$	467,424		$	365,635
Operating income			30,828			54,051			76,937			21,621
Net income.			7,699			24,396			39,189			6,783

	Quarter Ended
(Thousands of Dollars)	March 31, 2009			June 30, 2009			Sept. 30, 2009			Dec. 31, 2009
Operating revenues		$	368,983		$	328,140		$	397,094		$	365,006
Operating income			29,832			41,043			76,670			25,272
Net income			9,182			16,808			37,415			4,345

17. Sale of Lubbock Electric Distribution Assets

In November 2009, SPS entered into an asset purchase agreement with the city of Lubbock, Texas. This agreement had set forth that SPS would sell its electric distribution system assets within the city limits to LP&L for approximately $87 million. The sale and related transactions eliminate the inefficiencies of maintaining duplicate distribution systems, one by SPS and the other by the city-owned LP&L. SPS has provided indemnification to Lubbock for losses arising out of any breach of the representations, warranties and covenants under the related asset purchase agreement and for losses arising out of certain other matters, including pre-closing unknown liabilities. See Note 10 to the financial statements for further discussion of guarantees.

SPS served about 24,000 customers within Lubbock, representing about 25 percent of the total customers in the dually certified service area. As part of this transaction, SPS will continue to provide wholesale power to meet the electric load for these customers, initially by amending the current wholesale full-requirements contract with WTMPA, which provides service to LP&L through 2019 and then for an additional 25 years under a new contract directly with LP&L when the WTMPA contract terminates. Both of these wholesale power agreements provide for formula rates that change annually based on the actual cost of service. The formula rate with WTMPA reflects an initial 10.5 percent ROE. All or portions of this transaction were reviewed and approved by the PUCT, the NMPRC and the FERC.

Additionally, SPS and the city of Lubbock entered into an amended long-term treated sewage effluent water agreement under which SPS will continue to purchase waste water from the city for cooling SPS’ Jones Station southeast of Lubbock.

In October 2010, the transaction closed resulting in a pre-tax gain of approximately $20 million which will be shared with retail customers in Texas, and has been deferred as a regulatory liability pending the determination of the sharing by the PUCT.

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Item 9 — Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

During 2009 and 2010, and through the date of this report, there were no disagreements with the independent public accountants for SPS on accounting principles or practices, financial statement disclosures or auditing scope or procedures.

Item 9A — 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 SEC rules and forms. In addition, the disclosure controls and procedures ensure that information required to be disclosed is accumulated and communicated to management, including the chief executive officer (CEO) and chief financial officer (CFO), allowing timely decisions regarding required disclosure. As of Dec. 31, 2010, based on an evaluation carried out under the supervision and with the participation of SPS’ management, including the CEO and CFO, of the effectiveness of its disclosure controls and the procedures, the CEO and CFO have concluded that SPS’ disclosure controls and procedures were effective.

Internal Controls Over Financial Reporting

No change in SPS’ internal control over financial reporting has occurred during SPS’ most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, SPS’ internal control over financial reporting. SPS maintains internal control over financial reporting to provide reasonable assurance regarding the reliability of the financial reporting. SPS has evaluated and documented its controls in process activities, in general computer activities, and on an entity-wide level. During the year and in preparation for issuing its report for the year ended Dec. 31, 2010, on internal controls under section 404 of the Sarbanes-Oxley Act of 2002, SPS conducted testing and monitoring of its internal control over financial reporting. Based on the control evaluation, testing and remediation performed, SPS did not identify any material control weaknesses, as defined under the standards and rules issued by the Public Company Accounting Oversight Board (PCAOB) and as approved by the SEC and as indicated in Management Report on Internal Controls herein.

This annual report does not include an attestation report of SPS’ registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by SPS’ registered public accounting firm pursuant to rules of the Securities and Exchange Commission that permit SPS to provide only management’s report in this annual report.

Item 9B — Other Information

None

PART III

Items 10, 11, 12 and 13 of Part III of Form 10-K have been omitted from this report for SPS in accordance with conditions set forth in general instructions I (1) (a) and (b) of Form 10-K for wholly-owned subsidiaries.

Item 10 — Directors, Executive Officers and Corporate Governance

Item 11 — Executive Compensation

Item 12 — Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

Item 13 — Certain Relationships and Related Transactions, and Director Independence

Item 14 — Principal Accountant Fees and Services

Information concerning fees paid to the principal accountant for each of the last two years is contained in the Xcel Energy Proxy Statement for its 2011 Annual Meeting of Shareholders, which is incorporated by reference.

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PART IV

Item 15 — Exhibits, Financial Statement Schedules

1.		Financial Statements
		Management Report on Internal Controls — For the year ended Dec. 31, 2009.
		Report of Independent Registered Public Accounting Firm — For the years ended Dec. 31, 2009, 2008 and 2007.
		Statements of Income — For the three years ended Dec. 31, 2009, 2008 and 2007.
		Statements of Cash Flows — For the three years ended Dec. 31, 2009, 2008 and 2007.
		Balance Sheets — As of Dec. 31, 2009 and 2008.

2.		Schedule II — Valuation and Qualifying Accounts and Reserves for the years ended Dec. 31, 2009, 2008 and 2007.

3.		Exhibits

		*Indicates incorporation by reference
		+Executive Compensation Arrangements and Benefit Plans Covering Executive Officers and Directors

3.01*		Amended and Restated Articles of Incorporation dated Sept. 30, 1997 (Exhibit 3(a)(2) to Form 10-K (file no. 001-03789) dated March 3, 1998).
3.02*		By-laws dated Sept. 29, 1997 (Exhibit 3(b)(2) to Form 10-K (file no. 001-03789) dated March 3, 1998).
4.01*		Indenture dated Feb. 1, 1999 between SPS and The Chase Manhattan Bank (Exhibit 99.2 to Form 8-K (file no. 001-03789) dated Feb. 25, 1999).
4.02*		First Supplemental Indenture dated March 1, 1999 between SPS and The Chase Manhattan Bank (Exhibit 99.3 to Form 8-K (file no. 001-03789) dated Feb. 25, 1999).
4.03*		Second Supplemental Indenture dated Oct. 1, 2001 between SPS and The Chase Manhattan Bank (Exhibit 4.01 to Form 8-K (file no. 001-03789) dated Oct. 23, 2001).
4.04*		Third Supplemental Indenture dated Oct. 1, 2003 to the indenture dated Feb. 1, 1999 between SPS and JPMorgan Chase Bank, as successor Trustee, creating $100 million principal amount of Series C and Series D Notes, 6 percent due 2033 (Exhibit 4.04 to Xcel Energy Form 10-Q (file no. 001-03034) dated Nov. 13, 2003).
4.05*		Fourth Supplemental Indenture dated Oct. 1, 2006 between SPS and The Bank of New York, as successor Trustee (Exhibit 4.01 to Form 8-K (file no. 001-03789) dated Oct. 3, 2006).
4.06*		Red River Authority for Texas Indenture of Trust dated July 1, 1991 (Form 10-K, Aug. 31, 1991 -Exhibit 4(b)).
4.07*		Supplemental Trust Indenture dated as of Nov. 1, 2008 between SPS and The Bank of New York Mellon Trust Company, N.A., as successor Trustee, creating $250,000,000 principal amount of Series G Senior Notes, 8.75 percent due 2018 (Exhibit 4.01 of Form 8-K of SPS, dated Nov. 14, 2008 (file no. 001- 03789)).
10.01*+		Xcel Energy Omnibus Incentive Plan (Exhibit A to Form DEF-14A (file no. 001-03034) filed Aug. 29, 2000).
10.02*+		Xcel Energy Non-Qualified Pension Plan (2009 Restatement) (Exhibit 10.02 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008).
10.03*+		Amended and Restated Executive Long-Term Incentive Award Stock Plan (Exhibit 10.02 to Xcel Energy Form 10-Q (file no. 001-03034) for the quarter ended March 31, 1998).
10.04*+		New Century Energies Omnibus Incentive Plan (Exhibit A to New Century Energies, Inc. Form DEF 14A (file no. 001-12927) filed March 26, 1998).
10.05*+		Xcel Energy Senior Executive Severance Policy (2009 Amendment and Restatement) (Exhibit 10.05 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008).
10.06*+		Stock Equivalent Plan for Non-Employee Directors of Xcel Energy as amended and restated Jan. 1, 2009 (Exhibit 10.06 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008.
10.07*+		Xcel Energy Nonqualified Deferred Compensation Plan as amended and restated Jan. 1, 2009 (Exhibit 10.07 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008).
10.08*+		Xcel Energy Non-employee Directors’ Deferred Compensation Plan as amended and restated on Jan. 1, 2009 (Exhibit 10.08 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008).
10.09*+		Form of Services Agreement between Xcel Energy Services Inc. and utility companies (Exhibit H-1 to Form U5B (file no. 001-03034) dated Nov. 16, 2000).
10.10*+		Xcel Energy Omnibus Incentive Plan Form of Restricted Stock Unit Agreement (Exhibit 10.05 to Xcel Energy Form 10-Q (file no. 001-03034) dated June 30, 2005).
10.11*+		Xcel Energy Omnibus Incentive Plan Form of Performance Share Agreement (Exhibit 10.04 to Xcel Energy Form 10-Q (file no. 001-03034) dated June 30, 2005).
10.12*+		Xcel Energy Omnibus Incentive Plan Form of Restricted Stock Unit Agreement (Exhibit 10.07 to Xcel Energy Form 10-Q (file no. 001-03034) dated June 30, 2005).

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10.13*+		Xcel Energy Omnibus 2005 Incentive Plan (Appendix B to Exhibit 14A, Definitive Proxy Statement of Form 10-K of Xcel Energy (file no. 001-03034) dated April 11, 2005).
10.14*+		Xcel Energy Executive Annual Incentive Award Plan (Appendix C to Exhibit 14A, Definitive Proxy Statement of Form 10-K of Xcel Energy (file no. 001-03034) dated April 11, 2005).
10.15*+		Xcel Energy Supplemental Executive Retirement Plan as amended and restated Jan. 1, 2009 (Exhibit 10.17 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2008).
10.16*		Coal Supply Agreement (Harrington Station) between SPS and TUCO, dated May 1, 1979 (Form 8-K (file no. 001-03789), May 14, 1979 — Exhibit 3).
10.17*		Master Coal Service Agreement between Swindell-Dressler Energy Supply Co. and TUCO, dated July 1, 1978 (Form 8-K, (file no. 001-03789) May 14, 1979 — Exhibit 5(A)).
10.18*		Guaranty of Master Coal Service Agreement between Swindell-Dressler Energy Supply Co. and TUCO (Form 8-K, (file no. 3789) May 14, 1979 — Exhibit 5(B)).
10.19*		Coal Supply Agreement (Tolk Station) between SPS and TUCO dated April 30, 1979, as amended Nov. 1, 1979 and Dec. 30, 1981 (Form 10-Q, (file no. 3789) Feb. 28, 1982 — Exhibit 10(b)).
10.20*		Master Coal Service Agreement between Wheelabrator Coal Services Co. and TUCO dated Dec. 30, 1981, as amended Nov. 1, 1979 and Dec. 30, 1981 (Form 10-Q, (file no. 3789) Feb. 28, 1982 — Exhibit 10(c)).
10.21*		Power Purchase Agreement dated May 23, 1997 between Borger Energy Associates, L.P, and SPS.
10.22*		Amendment dated as of April 13, 2009 to the SPS Credit Agreement dated as of Dec. 14, 2006 (Exhibit 10.04 to Form 10-Q of Xcel Energy (file no. 001-03034) for the quarter ended June. 30, 2009).
10.23*		Credit Agreement dated Dec. 14, 2006 between SPS and various lenders (Exhibit 10.04 to Form 10-Q of Xcel Energy (file no. 001-03034) for the quarter ended Sept. 30, 2009).
10.24*+		Amendment dated Aug. 26, 2009 to the Xcel Energy Senior Executive Severance and Change-in-Control Policy (Exhibit 10.06 to Form 10-Q of Xcel Energy (file no. 001-03034) for the quarter ended Sept. 30, 2009).
10.25*+		Xcel Energy Executive Annual Incentive Award Plan Form of Restricted Stock Agreement (Exhibit 10.08 to Form 10-Q of Xcel Energy (file no. 001-03034) for the quarter ended Sept. 30, 2009).
10.26*+		Xcel Energy Inc. Executive Annual Incentive Award Plan (Exhibit 10.24 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2009).
10.27*+		Xcel Energy Executive Annual Incentive Award Plan (as amended and restated effective Feb. 17, 2010) (incorporated by reference to Appendix A to Schedule 14A, Definitive Proxy Statement to Xcel Energy (file no. 001-03034) dated April 6, 2010).
10.28*+		Xcel Energy 2005 Long-Term Incentive Plan (as amended and restated effective Feb. 17, 2010) (incorporated by reference to Appendix B to Schedule 14A, Definitive Proxy Statement to Xcel Energy (file no. 001-03034) dated April 6, 2010).
10.29*+		Xcel Energy 2010 Executive Annual Discretionary Award Plan (as amended and restated effective Dec. 15, 2010) (Exhibit 10.23 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2010).
10.30*+		Xcel Energy 2005 Long-Term Incentive Plan Form of Bonus Stock Agreement (Exhibit 10.24 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2010).
10.31*+		Xcel Energy 2005 Long-Term Incentive Plan Form of Performance Share Agreement (Exhibit 10.25 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2010).
10.32*+		Xcel Energy 2005 Long-Term Incentive Plan Form of Restricted Stock Unit Agreement (Exhibit 10.26 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2010).
12.01		Statement of Computation of Ratio of Earnings to Fixed Charges.
23.01		Consent of Independent Registered Public Accounting Firm.
31.01		Principal Executive Officer’s certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.02		Principal Financial Officer’s certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.01		Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.01		Statement pursuant to Private Securities Litigation Reform Act of 1995.

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SCHEDULE II

SOUTHWESTERN PUBLIC SERVICE CO.

VALUATION AND QUALIFYING ACCOUNTS

YEARS ENDED DEC. 31, 2010, 2009 AND 2008

(amounts in thousands of dollars)

			Additions
	Balance at Jan. 1		Charged to costs and expenses			Charged to other accounts (a)			Deductions from reserves (b)			Balance at Dec. 31
Reserve deducted from related assets:
Allowance for bad debts:
2010	$	4,415		$	3,990		$	998		$	4,308		$	5,095
2009		4,688			3,765			934			4,972			4,415
2008		3,166			4,745			1,074			4,297			4,688

(a)	Recovery of amounts previously written off.

(b)	Principally bad debts written off or transferred.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this annual report to be signed on its behalf by the undersigned, thereunto duly authorized.

	SOUTHWESTERN PUBLIC SERVICE CO.


February 28, 2011	/s/ DAVID M. SPARBY
	David M. Sparby Vice President, Chief Financial Officer and Director (Principal Financial Officer)

Pursuant to the requirements of the Securities Exchange Act of 1934, this report signed below by the following persons on behalf of the registrant and in the capacities and on February 28, 2011.

/s/ C. RILEY HILL		/s/ RICHARD C. KELLY
C. Riley Hill		Richard C. Kelly
President, Chief Executive Officer and Director		Chairman and Director


/s/ TERESA S. MADDEN		/s/ DAVID M. SPARBY
Teresa S. Madden		David M. Sparby
Vice President and Controller		Vice President, Chief Financial Officer and Director
(Principal Accounting Officer)		(Principal Financial Officer)


/s/ BENJAMIN G.S. FOWKE III
Benjamin G.S. Fowke III
Vice President and Director

SUPPLEMENTAL INFORMATION TO BE FURNISHED WITH REPORTS FILED PURSUANT TO SECTION 15(D) OF THE ACT BY REGISTRANTS WHICH HAVE NOT REGISTERED SECURITIES PURSUANT TO SECTION 12 OF THE ACT

SPS has not sent, and does not expect to send, an annual report or proxy statement to its security holder.

Attached files

SOUTHWESTERN PUBLIC SERVICE CO Reports

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