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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549

FORM 10-K

SOUTHWESTERN PUBLIC SERVICE COMPANY

(Exact name of registrant as specified in its charter)

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.

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

As of March 1, 2010, 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 2010 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).

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INDEX

This Form 10-K is filed by Southwestern Public Service Co. (SPS).  SPS is a wholly owned subsidiary of Xcel Energy Inc. Additional information on Xcel Energy is available in various filings with the U.S. Securities and Exchange Commission (SEC).  This report should be read in its entirety.

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PART I

Item l — Business

DEFINITION OF ABBREVIATIONS AND INDUSTRY TERMS

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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 2009.  SPS provides electric utility service to approximately 396,000 retail customers in Texas and New Mexico.  Approximately 74 percent of SPS’ retail electric operating revenues were derived from operations in Texas during 2009.  Generally, SPS’ earnings range from approximately 5 percent to 10 percent of Xcel Energy’s consolidated net income.

In November 2009, SPS announced it had entered into an agreement to sell certain SPS electric distribution assets in Lubbock, Texas, to Lubbock Power and Light (LP&L) for a price of $87 million.  SPS’ retail sales in Lubbock are 3 percent of SPS’ total energy sales.  SPS anticipates it will sell the same amount of power to the city under existing wholesale power arrangements with the West Texas Municipal Power Agency.

SPS focuses on growing through investments in electric rate base to meet growing customer demands, environmental and renewable energy initiatives and to maintain or increase reliability and quality of service to customers.  SPS files periodic rate cases, establishes formula rate or automatic rate adjustments with state and federal regulators to earn a return on its investment and recover costs of operations.

ELECTRIC UTILITY OPERATIONS

Overview

Climate Change and Clean Energy — Like most other utilities, SPS is 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.  SPS is subject to state RPS requirements which we believe they will be in a position to achieve by the applicable state deadlines.  Although the exact form and design of any federal RPS policy is uncertain at this time, we believe that we will be well-positioned to meet a federal standard as well, although the ultimate design of any federal policy could have a varied impact on SPS depending upon the energy efficiency and other standards imposed.  In addition, SPS’ electric generating facilities have been and are likely to be further subject to climate change legislation introduced at either the state or federal level within the next few years.  In 2009, the EPA took a number of steps toward the regulation of GHGs under the CAA.  By spring 2010, the EPA expects to promulgate regulations to control GHGs from mobile sources.  Thereafter, the EPA anticipates phasing-in permit requirements and regulation of GHGs for large stationary sources, such as power plants, in calendar year 2011.

While SPS is not currently subject to state or federal limits on its GHG emissions, SPS has undertaken a number of initiatives to prepare for climate change regulation and reduce our GHG emissions.  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, we would be granted the authority to recover the cost of these initiatives through rates.

Utility Restructuring and Retail Competition — The FERC has continued with 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 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.

The FERC has approved the open access transmission planning processes for the SPP, the RTO serving the SPS System.  SPS is also pursuing strengthening its transmission system internally to alleviate north and south congestion within the Texas Panhandle and other lines to increase the transfer capability between the Texas Panhandle and other electric systems in the SPP.  Transmission expansion plans include 345 KV lines from Tuco, Texas to Woodward, Okla.

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.  It is not certain if or when specific overlay projects may be constructed and placed in service.

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In 2002, Texas implemented retail competition, but it is presently limited to utilities within the ERCOT, which does not include SPS.  In Texas, SPS can file a plan to implement competition, subject to regulatory approval.  Local market conditions and political realities must be considered in proposing the transition to competition.  SPS has been unable to develop a plan for the Texas Panhandle to move toward competition that would be in the best interests of its customers.  As a result, SPS does not plan to propose retail competition in the Texas Panhandle.  New Mexico repealed its legislation related to retail electric utility competition.

The retail electric business faces competition as industrial and large commercial customers have the ability to own or operate facilities to generate their own electricity.  In 2009, FERC adopted rules requiring SPP to allow aggregators of retail customers (ARCs) to offer demand response aggregation services to end-use customers in the states served by SPS unless the applicable state regulatory authority prohibits ARCs from serving retail customers in their state.  The SPP compliance tariff filing is pending FERC action.  In addition, customers may have the option of substituting other fuels, such as natural gas or steam/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.  SPS can and does then appeal municipal rate decisions to the PUCT.  The NMPRC also has jurisdiction over the issuance of securities.  SPS is subject to the jurisdiction of the FERC with respect to its wholesale electric operations, accounting practices, wholesale sales for resale, the transmission of electricity in interstate commerce and certain natural gas transactions in interstate commerce.

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.

Because regulations require that actual fuel and purchased energy costs be recovered from ratepayers, 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 continue to use a monthly adjustment factor for a fuel and purchased power cost adjustment clause (FPPCAC) for SPS’ New Mexico retail jurisdiction.  NMPRC regulations require SPS to periodically request authority to continue using its FPPCAC.  In that proceeding, the NMPRC reviews SPS’ use of its FPPCAC since the filing of its previous fuel clause continuation filing.  SPS’ next fuel clause continuation filing is due Aug. 26, 2010.

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.

Performance-Based Regulation and Quality of Service Requirements — In Texas, SPS is subject to a QSP requiring SPS to comply with electric service reliability performance targets.  In October 2008, the PUCT staff served SPS with notice that it had initiated an investigation to determine whether SPS is in compliance with the Texas statutes and PUCT rules on reliability and continuity of service.

Texas EECRF Rider — PUCT regulations established the mechanism under which electric utilities may recover costs associated with providing energy efficiency programs.  That mechanism, an 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.  In accordance with this rule, SPS has removed its energy efficiency costs from its recent base rate proceeding, and has requested implementation of its EECRF rider to recover the remaining unamortized balance of historic costs and its projected 2008 and 2009 energy efficiency costs.  In September 2008, the PUCT concluded that the rule under which the application was filed does not apply to SPS and the energy efficiency costs could be recovered in the pending Texas retail base rate case.  SPS reached a negotiated settlement with the parties and included base rate recovery amounts explicitly designated for energy efficiency.  In February of 2010, the PUCT issued a proposed rule that would make SPS subject to the same requirements with respect to the EECRF as other utilities in the state.

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New Mexico Energy Efficiency Disincentive Rulemaking — During the last legislative session, increased energy efficiency goals and more affirmative disincentive language were adopted.  The NMPRC is currently conducting a rulemaking proceeding to update the energy efficiency rule, consistent with the legislative changes.

SPS Participation in the SPP RTO — In October 2007, the NMPRC ordered an investigation of the benefits of SPS’ participation in the SPP RTO.  The conversion of SPS’ retail load to transmission service under the SPP tariff effective Feb. 1, 2010 was mandatory under the SPP membership agreement.  In September 2009, the parties filed a stipulation resolving all issues in the proceeding for a five year interim period.  On Feb. 2, 2010, the NMPRC approved the settlement authorizing SPS to put its retail load under the SPP OATT effective Jan. 1, 2010.

TUCO to Woodward District Extra High Voltage (EHV) Interchange — The SPP, as a part of its balance portfolio plan, issued a notice in June 2009 directing 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.  A decision is pending.

Capacity and Demand

Uninterrupted system peak demand for SPS for each of the last three years and the forecast for 2010, assuming normal weather, is listed below.

The peak demand for the SPS system typically occurs in the summer.  The 2009 uninterrupted system peak demand for SPS occurred on July 14, 2009.  Peak demand in 2010 is expected to decrease due to the expiration of a wholesale contract with El Paso Electric.

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 a particular generating source 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 — SPS’s IRP in New Mexico was approved in August 2009 under the NMPRC’s rule.

Renewable Energy Portfolio Plan — SPS is required to develop and implement a renewable portfolio plan in New Mexico in which at least six percent of its energy to serve its New Mexico retail customers is produced by renewable resources in 2010.  The renewable standard increases to ten percent in 2011.  SPS primarily fulfills its renewable portfolio requirements through purchased wind energy generation in eastern New Mexico.  In October 2009, the NMPRC granted SPS a variance to allow SPS to delay meeting its solar energy requirement until 2012 with the provision that SPS will make-up any shortfall of solar energy requirement for 2011 during 2012 through 2014.  SPS has executed certain commercial agreements for solar energy purchased power and SPS sought regulatory approval in January 2010.

Pending Resource Solicitations — SPS released four RFP’s during 2008, targeting capacity and energy resources as follows:

·                  up to 200 MW under terms of 3 to 8 years with deliveries beginning either June 2010 or June 2011;

·                  up to 250 MW of wind resources located in the Texas portion of the SPS balancing authority;

·                  up to 600 MW of dispatchable resources with terms of up to 20 years and deliveries beginning either June 2012 or June 2013; and

·                  a non-wind RFP for renewable energy in New Mexico consisting of solar and biomass technologies.

SPS awarded a winning bid to Sun Edison for 50 MW of photovoltaic solar to be installed at five sites (10 MW each) in New Mexico and signed contracts in 2009, and a request for approval was filed in January 2010.

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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.

All of the transmission arrangements for the SPS systems are through FERC approved OATT.  SPS also has several transmission arrangements through the SPP OATT.  The SPP is a RTO that, among other things, administers an OATT for all its members.  SPS’ entire service territory is within the SPP footprint, and SPS is a member of the SPP.  The SPP owns no transmission facilities.  Rather, the SPP is responsible for ensuring that transmission service across facilities owned by others, including SPS, is made available and used on a reliable and non-discriminatory basis.  These OATTs contain policies and procedures for reliable use of the transmission systems for transmission, generation and load variations.

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.

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, Inc. (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, 2009, coal inventories at the Harrington and Tolk sites were approximately 46 and 54 days supply, respectively.  TUCO has coal agreements to supply 89 percent of SPS’ coal requirements in 2010, 37 percent of SPS’ coal requirements in 2011, and 35 percent of SPS’ coal requirements in 2012, 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.  The supply contracts expire in 2010.  The transportation and storage contracts expire in various years from 2010 to 2033.  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, 2009, SPS’ commitments related to supply contracts were approximately $47 million and transportation and storage contracts were approximately $253 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, including 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 13 to the financial statements for a discussion of other regulatory matters.

FERC Rules Implementing Energy Policy Act of 2005 (Energy Act) — 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.

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

Compliance with NERC Protective Maintenance Standards — In 2008, SPS filed self-reports with the SPP, the NERC regional entity for the SPS system, relating to failure to complete certain generation station battery tests, relay maintenance intervals and record keeping associated with certain critical infrastructure protection standards.  In 2009, SPS reached agreement with the SPP that would resolve all open audit findings and self reports by payment of a non-material penalty.  SPS is in the process of developing a definitive settlement agreement with SPP.  This settlement agreement will be subject to NERC and FERC approval.

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.

Market Based Rate Rules — SPS filed a request for market-based rate reauthorization with the FERC in July 2009.  That request is pending FERC action.  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 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 and rules and approved tariffs.  The report represents the preliminary conclusions of the DOI and is subject to additional procedures.  The report does not constitute a finding by the FERC, which may accept, modify or reject any or all of the preliminary conclusions in the report.  Xcel Energy disagrees with the preliminary report.  Xcel Energy continues to cooperate with the DOI investigation.  Given the preliminary nature of this matter, Xcel Energy is unable to determine if the resolution of this matter will have a material adverse impact on operations, cash flows or financial condition.

SPP Transmission Cost Recovery — The SPP transmission tariff currently establishes the mechanism for recovering costs associated with base plan transmission projects, which are transmission projects required to maintain reliability, and for balanced portfolio transmission projects that promote economic expansion of the SPP grid.  Currently, for base plan transmission projects, one-third of the costs are collected on an SPP region-wide basis and the remaining two-thirds are recovered from individual pricing zone(s) in SPP using a power flow analysis.  For balanced portfolio projects, 100 percent of the costs are recovered on an SPP region-wide basis.  SPP is currently re-evaluating this methodology, and the SPP board of directors has preliminarily approved a highway/byway funding approach that would allocate costs as follows:

·                  For projects rated at a voltage level less than 100 KV, all costs would be recovered from the pricing zone of the project;

·                  For projects rated at a voltage level between 100 KV and 300 KV, one-third of the costs would be recovered on an SPP region-wide basis and two-thirds would be recovered from the pricing zone of the project; and

·                  For projects rated at a voltage level greater than 300 KV, 100 percent of costs would be recovered on an SPP region-wide basis.

The details of the application of the highway/byway funding approach are still under development in SPP and any methodology would still be subject to FERC approval.  The uncertainty surrounding allocation of transmission costs in SPP could affect the timing or location of transmission additions as well as near-term SPS transmission investment.

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Electric Operating Statistics

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 14 to the financial statements.

EMPLOYEES

The number of full-time SPS employees at Dec. 31, 2009 and 2008 was 1,186 and 1,191, respectively.  Of these full-time employees, 795, or 67 percent, and 804, or 68 percent, respectively, are covered under collective bargaining agreements.  See Note 8 to the financial statements for further discussion of the bargaining agreements.  Employees of Xcel Energy Services Inc., a subsidiary of Xcel Energy, also provide services to SPS and are not considered in the above amounts.

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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 and manage material risk; management is responsible for identifying and managing the risks, while directors oversee and hold management accountable.  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 like 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 where a business area may take inappropriate risk to meet goals.

The goal of the risk management process is to mitigate the risks inherent in the implementation of Xcel Energy’s and SPS’ strategy.  The process for risk management and mitigation includes our code of conduct and other compliance policies, formal structures and groups, and overall business management.  At a threshold level, we have developed a robust compliance program and promotes a culture of compliance, which mitigates risk.  In addition to the code of conduct, we have a robust compliance program, including policies, training and reporting options. 

Building on the culture of compliance, we manage and mitigate risks through formal 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. 

We confront legislative and regulatory policy and compliance risks, including risks related to climate change and emission of CO2 and 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.

Management provides information to the Xcel Energy’s Board in presentations and communications over the course of the Board calendar.  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.

Risks Associated with Our Business

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.

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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.  If all of our costs are not recovered through customer rates, we could incur financial operating losses, which, over the long term, could jeopardize our ability to meet our financial obligations.

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.

We are subject to interest rate risk.

If interest rates increase, we may incur increased interest expense on variable interest rate debt, short-term borrowings or incremental long-term debt, which could have an adverse impact on our operating results.

We are subject to capital market risk.

Our operations require significant capital investment in property, plant and equipment; consequently, we are an active participant in debt 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 events throughout the world economy.  Capital market disruption events, such as the collapse in the U.S. sub-prime mortgage market and subsequent broad financial market stress, 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.

We are subject to credit risks.

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

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

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

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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 the PJM Interconnection 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.

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, we may be unable to fulfill contractual obligations to our retail, wholesale and other customers at previously authorized or anticipated costs.  Any such supply shortages 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 unique operating conditions such as generation fuels mix, availability of water for cooling, availability of fuel transportation, electric generation capacity, transmission, etc.

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, 2009, 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 operating and maintenance 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, 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.

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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 an increase in 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.  Severe weather impacts our service territories, primarily when thunderstorms, tornadoes and snow or ice storms occur.  We include storm restoration in our budgeting process as a normal business expense and we anticipate continuing to do so.  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.

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

Legislative and regulatory responses related to climate change and new interpretations of existing laws through climate change litigation create financial risk.  Increased public awareness and concern 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 GHG and federal legislation has been introduced in both houses of Congress.  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.  On Dec. 7, 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 creates a mandatory duty for the EPA to regulate GHGs from light duty motor vehicles.  The EPA has proposed to finalize GHG efficiency standards for light duty vehicles by spring 2010.  Thereafter, the EPA anticipates phasing-in permit requirements and regulation of GHGs for large stationary sources, such as power plants, in calendar year 2011.  Xcel Energy, our parent company, is 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 14, Commitments and Contingent Liabilities, in our notes to the financial statements.  While Xcel Energy believes 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.

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Many of the federal and state climate change legislative proposals, such as ACES, use a cap and trade policy structure, in which GHG emissions from a broad cross-section of the economy would be subject to an overall cap.  Under the proposals, the cap becomes more stringent with the passage of time.  The proposals establish mechanisms for GHG sources, such as power plants, to obtain “allowances” or permits to emit GHGs during the course of a year.  The sources may use the allowances to cover their own emissions or sell them to other sources that do not hold enough 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 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 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 operating and maintenance costs incurred to comply with the mandates, it could have a material adverse effect on our results of operations.

For further discussion, see Note 14 to the financial statements.

Economic conditions could negatively impact our business.

Our operations are affected by local, national and worldwide economic conditions.  The consequences of a prolonged recession may include a lower level of economic activity and uncertainty with respect to energy prices and the capital and commodity markets.  A lower level of economic activity might result in a decline in energy consumption, and 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.  It is expected that commercial and industrial customers will be impacted first with residential customers following, if such circumstances occur.  See credit risk section for more related information.

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

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.

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 implement 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.

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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.

We are subject to business continuity risks associated with our ability to respond to unforeseen events.

The term business continuity refers to the ability of an entity to maintain day-to-day operations in response to unforeseen events.  While the immediate response to such events may be part of a pre-existing disaster recovery plan, business continuity is a broader concept that refers to how well the company responds to subsequent pressures on its day-to-day operations.  The company’s response may have been initially triggered by an event, but when combined with other factors, it has an even greater and longer lasting impact on the firm’s on going business operations.

Our response to unforeseen events will, in part, determine the financial impact of the event on our financial condition and results.  It is difficult to predict the magnitude of such events and associated impacts.

We are subject to information security risks.

A security breach of our information systems could subject us to financial harm associated with theft or inappropriate release of certain types of information, including, but not limited to, customer or system operating information.  We are unable to quantify the potential impact of such an event.

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 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.

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.

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.

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Increasing costs associated with health care plans may adversely affect our results of operations, financial position or liquidity.

The costs of providing health care benefits to our employees and retirees have increased substantially in recent years.  We believe that our employee benefit costs, including costs related to health care plans for our employees and former employees, will continue to rise.  The increasing costs and funding requirements associated with our health care plans may adversely affect our results of operations, financial position, or liquidity.

As we are a subsidiary of Xcel Energy, we may be negatively affected by events at 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 Xcel Energy’s credit ratings and access to capital were restricted, 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.

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 events were to occur, we may need to seek alternative sources of funds to meet our cash needs.

As of Dec. 31, 2009, Xcel Energy had approximately $7.9 billion of long-term debt and $1.0 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 of 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, 2009, Xcel Energy had guarantees outstanding with a maximum stated amount of approximately $76.4 million and $18.0 million of exposure.  Xcel Energy has also provided indemnities to sureties in respect of bonds for the benefit of its subsidiaries.  The total amount of bonds with these indemnities outstanding as of Dec. 31, 2009, was approximately $29.9 million.  Xcel Energy’s total exposure under these indemnities 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 the 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.

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 2009, 2008 and 2007 we paid $66.8 million, $61.8 million and $69.1 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.

Item 1B — Unresolved Staff Comments

None.

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Item 2 — Properties

Electric utility overhead and underground transmission and distribution lines (measured in conductor miles) at Dec. 31, 2009:

SPS had 437 electric utility transmission and distribution substations at Dec. 31, 2009.

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 14 to the financial statements.  For a discussion of proceedings involving utility rates and other regulatory matters, see Item 1 for Public Utility Regulation and Summary of Recent Federal Regulatory Developments and Note 13 to the financial statements.

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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 51 percent and 48 percent at Dec. 31, 2009 and 2008, 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 2009 and 2008 were as follows:

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).

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).

Forward Looking Information

The following discussion and analysis by management focuses on those factors that had a material effect on the financial condition and results of operations of SPS during the periods presented, or are expected to have a material impact in the future.  It should be read in conjunction with the respective accompanying financial statements and notes to the financial 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’s Form 10-K for the year ended Dec. 31, 2009 and Exhibit 99.01 to SPS’ Form 10-K for the year ended Dec. 31, 2009.

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Results of Operations

SPS’ net income was approximately $67.8 million for 2009, compared with approximately $31.8 million for 2008.

Electric Revenues and Margins

Electric production expenses tend to vary with the quantity of electricity sold and changes in the unit costs of fuel and purchased power.  The fuel and purchased power cost recovery mechanisms of the Texas and New Mexico jurisdictions may not allow for complete recovery of all expenses and, therefore, dramatic changes in costs or periods of extreme temperatures can impact earnings.

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

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

Electric Revenues

Electric Margin

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Non-Fuel Operating Expense and Other Items

Other Operating and Maintenance Expenses — Other operating and maintenance expenses for 2009 increased $13.9 million, or 6.7 percent, compared to 2008.  The following summarizes the components of the changes for the year ended Dec. 31:

Demand Side Management (DSM) Program Expenses — DSM program expenses for 2009 decreased by approximately $1.4 million, or 16.2 percent, compared with 2008.  This decrease was due to the settlement of the Texas rate case in 2009 which extended the amortization period from 4 years to 10 years.  DSM program expenses are recovered through riders or base rates.

Depreciation and Amortization — Depreciation and amortization increased by approximately $5.9 million, or 6 percent, for 2009 compared with 2008, primarily due to the amortization of rate case expenses and regulatory assets and overall system growth.

Other Income, Net — Other income, net, decreased by $5.6 million for 2009 compared with 2008.  The decrease was primarily due to lower interest income in 2009.

Allowance for Funds Used During Construction, Debt and Equity (AFUDC) — AFUDC increased by approximately $4.3 million for 2009 compared with 2008.  The increase was due to the debt to equity split that began in January of 2009.

Interest Charges — Interest charges increased by $10.6 million, or 17.3 percent, for 2009 compared with 2008.  The increase was primarily due to increased long-term debt levels necessary to repay short-term borrowings and to fund capital investments throughout 2009 compared to 2008.

Income Taxes — Income tax expense increased by approximately $19.5 million for 2009, compared with 2008.  The effective tax rate was 37.4 percent for 2009, compared with 39.8 percent for 2008.  The increase in tax expense and the lower effective tax rate for 2009 were primarily due to higher pretax income in 2009.

The effective tax rate for 2009 differs from the statutory federal income tax rate, primarily due to state income tax expense.  The effective tax rate for 2008 differs from the statutory federal income tax rate, primarily due to state income tax expense and plant related regulatory tax expense, partially offset by prior year state tax benefit.  See Note 7 to the financial statements.

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 10 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 within each rate-regulated operation 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.

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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.

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.  The 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 18 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, 2009.  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, 2009, the company’s internal control over financial reporting is effective based on those criteria.

SPS’ independent auditors have issued an audit report on the company’s internal control over financial reporting.  Their report appears herein.

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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, 2009 and 2008, 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, 2009.  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.  An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements.  An audit also includes 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, 2009 and 2008, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2009, 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.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2009, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 1, 2010 expressed an unqualified opinion on the Company’s internal control over financial reporting.

/s/ DELOITTE & TOUCHE LLP

Minneapolis, Minnesota

March 1, 2010

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Stockholder

Southwestern Public Service Company

We have audited the internal control over financial reporting of Southwestern Public Service Company (the “Company”) as of December 31, 2009, based on criteria established Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.  The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management Report on Internal Controls over Financial Reporting.  Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

We conducted our audit 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 effective internal control over financial reporting was maintained in all material respects.  Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances.  We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.  A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis.  Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) the financial statements and financial statement schedule as of and for the year ended December 31, 2009 of the Company and our report dated March 1, 2010 expressed an unqualified opinion on those financial statements and financial statement schedule.

/s/ DELOITTE & TOUCHE LLP

Minneapolis, Minnesota

March 1, 2010

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Table of Contents

SOUTHWESTERN PUBLIC SERVICE CO.

STATEMENTS OF INCOME

(amounts in thousands of dollars)

See Notes to Financial Statements

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SOUTHWESTERN PUBLIC SERVICE CO.

STATEMENTS OF CASH FLOWS

(amounts in thousands of dollars)

See Notes to Financial Statements

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SOUTHWESTERN PUBLIC SERVICE CO.

BALANCE SHEETS

(amounts in thousands of dollars)