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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

(Mark One)

For the fiscal year ended December 31, 2002

OR

El Paso Electric Company

(Exact name of registrant as specified in its charter)

Registrant’s telephone number, including area code: (915) 543-5711

Securities Registered Pursuant to Section 12(b) of the Act:

Securities Registered Pursuant to Section 12(g) of the Act:

None

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.    YES  x    NO  ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of 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 an accelerated filer (as defined in Rule 12b-2 of the Act).    YES  x    NO  ¨

As of June 28, 2002, the aggregate market value of the voting stock held by non-affiliates of the registrant was $684,376,158 (based on the closing price as quoted on the American Stock Exchange on that date).

As of March 7, 2003, there were 49,339,782 shares of the Company’s no par value common stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant’s definitive Proxy Statement for the 2003 annual meeting of its shareholders are incorporated by reference into Part III of this report.

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DEFINITIONS

The following abbreviations, acronyms or defined terms used in this report are defined below:

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PART I

Item 1. Business

General

El Paso Electric Company is a public utility engaged in the generation, transmission and distribution of electricity in an area of approximately 10,000 square miles in west Texas and southern New Mexico. The Company also serves wholesale customers in the states of Texas and New Mexico and in the Republic of Mexico. The Company owns or has significant ownership interests in six electrical generating facilities providing it with a total capacity of approximately 1,500 MW. For the year ended December 31, 2002, the Company’s energy sources consisted of approximately 52% nuclear fuel, 25% natural gas, 6% coal, 17% purchased power and less than 1% generated by wind turbines.

The Company serves approximately 316,000 residential, commercial, industrial and wholesale customers. The Company distributes electricity to retail customers principally in El Paso, Texas and Las Cruces, New Mexico (representing approximately 57% and 8%, respectively, of the Company’s electric utility operating revenues for the year ended December 31, 2002). In addition, the Company’s wholesale sales include sales for resale to the CFE, as well as sales to power marketers and other electric utilities. Principal industrial and other large customers of the Company include steel production, copper and oil refining, and United States military installations, including the United States Army Air Defense Center at Fort Bliss in Texas and White Sands Missile Range and Holloman Air Force Base in New Mexico.

The Company’s principal offices are located at the Stanton Tower, 100 North Stanton, El Paso, Texas 79901 (telephone 915-543-5711). The Company was incorporated in Texas in 1901. As of March 7, 2003, the Company had approximately 1,000 employees, 32% of whom are covered by a collective bargaining agreement.

The Company makes available free of charge through its website, www.epelectric.com, its annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and all amendments to those reports as soon as reasonably practicable after such material is electronically filed with or furnished to the Securities and Exchange Commission.

Facilities

The Company’s net installed generating capacity of approximately 1,500 MW consists of approximately 600 MW from Palo Verde Units 1, 2 and 3, 482 MW from its Newman Power Station, 246 MW from its Rio Grande Power Station, 104 MW from Four Corners Units 4 and 5, 68 MW from its Copper Power Station and 1.32 MW from Hueco Mountain Wind Ranch.

Palo Verde Station

The Company owns a 15.8% interest in each of the three nuclear generating units and Common Facilities at Palo Verde, in Wintersburg, Arizona. The Palo Verde Participants include the Company and six other utilities: APS, Southern California Edison Company (“SCE”), PNM, Southern California Public Power Authority, Salt River Project Agricultural Improvement and Power District (“SRP”) and the Los Angeles Department of Water and Power. APS serves as operating agent for Palo Verde.

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The NRC has granted facility operating licenses and full power operating licenses for Palo Verde Units 1, 2 and 3, which expire in 2024, 2025 and 2027, respectively. In addition, the Company is separately licensed by the NRC to own its proportionate share of Palo Verde.

Pursuant to the ANPP Participation Agreement, the Palo Verde Participants share costs and generating entitlements in the same proportion as their percentage interests in the generating units, and each participant is required to fund its share of fuel, other operations, maintenance and capital costs. The ANPP Participation Agreement provides that if a participant fails to meet its payment obligations, each non-defaulting participant shall pay its proportionate share of the payments owed by the defaulting participant.

Decommissioning. Pursuant to the ANPP Participation Agreement and federal law, the Company must fund its share of the estimated costs to decommission Palo Verde Units 1, 2 and 3, including the Common Facilities, over their estimated useful lives of 40 years (to 2024, 2025 and 2027, respectively). The Company’s funding requirements are determined every three years based upon engineering cost estimates performed by outside engineers retained by APS.

In accordance with the ANPP Participation Agreement, the Company is required to establish a minimum accumulation and a minimum funding level in its decommissioning account at the end of each annual reporting period during the life of the plant. In order for the Company to remain above its minimum funding level as of December 31, 2002, an additional deposit of $4.7 million was made in January 2003 due to significant market value declines in its invested decommissioning funds. As a result of the recent declines in the financial markets, the Company anticipates its cash contributions to the decommissioning trust funds will increase as compared to recent years.

In August 2002, the Palo Verde Participants approved the 2001 Palo Verde decommissioning study. Some changes in the cost calculations occurred between the prior 1998 study and the 2001 study. The 2001 study determined that the Company must fund approximately $311.6 million (stated in 2001 dollars) to cover its share of decommissioning costs. The previous cost estimate from the 1998 study determined that the Company would fund approximately $280.5 million (stated in 1998 dollars). The 2001 estimate reflects an 11.1% increase, or 3.6% average annual increase, from the 1998 estimate primarily due to increases in estimated costs for site restoration at each unit, pre and post-shutdown transitioning and decommissioning preparations, spent fuel storage after operations have ceased and for the Unit 2 steam generator storage. The decommissioning study is stated in constant dollars and makes no inflation assumptions. See “Spent Fuel Storage” below.

Although the 2001 study was based on the latest available information, there can be no assurance that decommissioning cost estimates will not continue to increase in the future or that regulatory requirements will not change. In addition, until a new low-level radioactive waste repository opens and operates for a number of years, estimates of the cost to dispose of low-level radioactive waste are subject to significant uncertainty. The Company’s decommissioning funding plan assumes an average annual increase in cost estimates of 3%. The decommissioning study is updated every three years and a new study is expected to be completed in 2004. See “Disposal of Low-Level Radioactive Waste” below.

Historically, regulated utilities such as the Company have been permitted to collect in rates the costs of nuclear decommissioning. Under deregulation legislation in both Texas and New Mexico, the Company expects to continue to be able to collect from customers the costs of decommissioning. The collection mechanism in both states is anticipated to be a “non-bypassable wires charge” through which

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all customers, even those who choose to purchase energy from a supplier other than the Company, are to pay a fee to the Company’s electric distribution subsidiary. The amount of this fee will be approved by the Texas and New Mexico Commissions and is expected to cover decommissioning. In the Company’s case, collection of the fee will begin in Texas following the end of the Freeze Period in August 2005 and in New Mexico in 2007, which is the current date for the beginning of retail competition. See “Regulation – Texas Regulatory Matters – Deregulation” for further discussion. While the Company is entitled to collect decommissioning costs in full under Texas law, there is some uncertainty in New Mexico as to the ability to collect 100% of such costs. See “Regulation – New Mexico Regulatory Matters.”

Spent Fuel Storage. The original spent fuel storage facilities at Palo Verde will have sufficient capacity to store all fuel expected to be discharged from normal operation of all three Palo Verde units through 2003. Alternative on-site storage facilities and casks are being constructed to supplement existing facilities. In March 2003, APS began removing spent fuel from the original facilities as necessary and placing it in special storage casks which will be stored at the new facilities until accepted by the DOE for permanent disposal. The decommissioning study assumes that costs to store fuel on-site will become the responsibility of the DOE after the year 2037. APS believes that spent fuel storage or disposal methods will be available for use by Palo Verde to allow its continued operation through the term of the operating license for each Palo Verde unit.

Pursuant to the Nuclear Waste Policy Act of 1982, as amended in 1987 (the “Waste Act”), the DOE is legally obligated to accept and dispose of all spent nuclear fuel and other high-level radioactive waste generated by all domestic power reactors. In accordance with the Waste Act, the DOE entered into a spent nuclear fuel contract with the Company and all other Palo Verde Participants. The DOE has previously reported that its spent nuclear fuel disposal facilities would not be in operation until 2010. Subsequent judicial decisions required the DOE to start accepting spent nuclear fuel by January 31, 1998. The DOE did not meet that deadline, and the Company cannot currently predict when spent fuel shipments to the DOE’s permanent disposal site will commence.

The Company expects to incur significant on-site spent fuel storage costs during the life of Palo Verde that the Company believes are the responsibility of the DOE. These costs will be amortized over the burn period of the fuel that will necessitate the use of the alternative on-site storage facilities until an agreement is reached with the DOE for recovery of these costs. APS is monitoring pending litigation between the DOE and other nuclear operators before initiating legal proceedings or other procedural measures on behalf of the Palo Verde Participants to recover monetary damages associated with the delay in DOE’s acceptance of spent fuel. The Company is unable to predict the outcome of these matters at this time.

Disposal of Low-Level Radioactive Waste. Congress has established requirements for the disposal by each state of low-level radioactive waste generated within its borders. Arizona, California, North Dakota and South Dakota have entered into a compact (the “Southwestern Compact”) for the disposal of low-level radioactive waste. California will act as the first host state of the Southwestern Compact, and Arizona will serve as the second host state. The construction and opening of the California low-level radioactive waste disposal site in Ward Valley has been delayed due to extensive public hearings, disputes over environmental issues and review of technical issues related to the proposed site. Palo Verde is projected to undergo decommissioning during the period in which Arizona will act as host for the Southwestern Compact. The opposition, delays, uncertainty and costs experienced in California demonstrate possible roadblocks that may be encountered when Arizona seeks to open its own waste

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repository. APS currently believes that interim low-level waste storage methods are or will be available for use by Palo Verde to allow its continued operation and to safely store low-level waste until a permanent disposal facility is available.

Steam Generators. Palo Verde has experienced degradation in the steam generator tubes of each unit. The projected service lives of the Palo Verde steam generators are reassessed by APS periodically in conjunction with inspections made during scheduled outages at the Palo Verde units. In December 1999, the Palo Verde Participants unanimously approved installation of new steam generators at Unit 2. This decision was based on an analysis of the net economic benefit from expected improved performance of the unit and the need to realize continued production from that unit over its full licensed life. Steam generator replacement, together with ancillary capital improvements, also permits an increase of power output. Fabrication and delivery of Unit 2 steam generators is complete. The components are being stored at Palo Verde in preparation for installation in the fall of 2003. The Company’s portion of costs associated with construction and installation of new steam generators in Unit 2, together with power uprate modifications, is currently estimated to be $35.9 million or $40.8 million with replacement power costs.

APS has identified accelerated degradation in the tubes in Units 1 and 3 and has concluded that it is economically desirable to replace the steam generators at those units. While analyses related to timing of installation of steam generators at Units 1 and 3 are ongoing, the Company and the other participants approved the expenditure of $199.2 million (the Company’s portion being $31.5 million) for fabrication and transport of steam generators for Units 1 and 3. In addition, APS has proposed, and the participants have approved the expenditure of $28.4 million (the Company’s portion being $4.5 million) for pre-installation and power uprate work for Units 1 and 3. In addition to these approved amounts, $220.1 million (the Company’s portion being $34.7 million) is necessary to fund installation of the Units 1 and 3 replacement steam generators and complete power uprates at those units. Present plans are for replacement steam generators to be installed at Units 1 and 3 in 2005 and 2007, respectively.

The eventual total cost of steam generator replacement for Units 1, 2 and 3 is currently estimated to be $674.8 million excluding replacement power costs (the Company’s portion being $106.6 million of which $26.6 million, excluding capitalized interest and overhead, is in construction work in progress as of December 31, 2002) payable over a period of 11 years starting in 1998. The Company expects its portion will be funded with internally generated cash.

The Texas Rate Stipulation precludes the Company from seeking a rate increase to recover additional capital costs incurred at Palo Verde during the Freeze Period. The Company cannot assure that it will be able to recover these capital costs through its wholesale power rates or its competitive retail rates that become applicable after the start of competition. See also Part II, Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Overview.”

Liability and Insurance Matters. In 1957, Congress enacted the Price-Anderson Act as an amendment to the Atomic Energy Act to provide a system of financial protection for persons who may be injured and persons who may be liable for a nuclear incident. The Price-Anderson Act will expire on December 31, 2003, unless extended by Congress. Existing licensees, such as the Company, are grandfathered and will continue to be subject to the provisions of the Price-Anderson Act in the event Congress does not further extend its expiration date. The amount of DOE indemnification currently available under the act is $9.43 billion. Additionally, the Palo Verde Participants have public liability insurance against nuclear energy hazards up to the full limit of liability under the Price-Anderson Act.

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The insurance consists of $200 million of primary liability insurance provided by commercial insurance carriers, with the balance being provided by an industry-wide retrospective assessment program, pursuant to which industry participants would be required to pay a retrospective assessment to cover any loss in excess of $200 million. Effective August 1998, the maximum retrospective assessment per reactor for each nuclear incident is approximately $88.1 million, subject to an annual limit of $10 million per incident. Based upon the Company’s 15.8% interest in Palo Verde, the Company’s maximum potential retrospective assessment per incident is approximately $41.8 million for all three units with an annual payment limitation of approximately $4.7 million.

The Palo Verde Participants maintain “all risk” (including nuclear hazards) insurance for damage to, and decontamination of, property at Palo Verde in the aggregate amount of $2.75 billion, a substantial portion of which must first be applied to stabilization and decontamination. The Company also has obtained insurance against a portion of any increased cost of generation or purchased power which may result from an accidental outage of any of the three Palo Verde units if the outage exceeds 12 weeks.

Newman Power Station

The Company’s Newman Power Station, located in El Paso, Texas, consists of three steam-electric generating units and one combined cycle generating unit with an aggregate capacity of approximately 482 MW. The units operate primarily on natural gas, but can also operate on fuel oil.

Rio Grande Power Station

The Company’s Rio Grande Power Station, located in Sunland Park, New Mexico, adjacent to El Paso, Texas, consists of three steam-electric generating units with an aggregate capacity of approximately 246 MW. The units operate primarily on natural gas, but can also operate on fuel oil.

Four Corners Station

The Company owns a 7% interest, or approximately 104 MW, in Units 4 and 5 at Four Corners, located in northwestern New Mexico. The two coal-fired generating units each have a total generating capacity of 739 MW. The Company shares power entitlements and certain allocated costs of the two units with APS (the Four Corners operating agent) and the other participants, PNM, TEP, SCE and SRP.

Four Corners is located on land held on easements from the federal government and a lease from the Navajo Nation that expires in 2016, with a one-time option to extend the term for an additional 25 years. Certain of the facilities associated with Four Corners, including transmission lines and almost all of the contracted coal sources, are also located on Navajo land. Units 4 and 5 are located adjacent to a surface-mined supply of coal.

Copper Power Station

The Company’s Copper Power Station, located in El Paso, Texas, consists of a 68 MW combustion turbine used primarily to meet peak demands. The unit operates primarily on natural gas, but can also operate on fuel oil. The Company leases the combustion turbine and other generation

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equipment at the station under a lease that expires in July 2005, with an extension option for two additional years.

Hueco Mountain Wind Ranch

The Company’s Hueco Mountain Wind Ranch, located in Hudspeth County, east of El Paso County and adjacent to Horizon City, currently consists of two wind turbines with a total capacity of 1.32 MW.

Transmission and Distribution Lines and Agreements

The Company owns or has significant ownership interests in four major 345 kV transmission lines in New Mexico, three 500 kV lines in Arizona, and owns the distribution network within its New Mexico and Texas retail service area. The Company is also a party to various transmission and power exchange agreements that, together with its owned transmission lines, enable the Company to deliver its energy entitlements from its remote generation sources at Palo Verde and Four Corners to its service area. Pursuant to standards established by the North American Electric Reliability Council and the Western Electricity Coordinating Council, the Company operates its transmission system in a way that allows it to maintain complete system integrity in the event that any one of these transmission lines is out of service.

Springerville-Diablo Line. The Company owns a 310-mile, 345 kV transmission line from TEP’s Springerville Generating Plant near Springerville, Arizona, to the Luna Substation near Deming, New Mexico, and to the Diablo Substation near Sunland Park, New Mexico. This transmission line provides an interconnection with TEP for delivery of the Company’s generation entitlements from Palo Verde and, if necessary, Four Corners.

Arroyo-West Mesa Line. The Company owns a 202-mile, 345 kV transmission line from the Arroyo Substation located near Las Cruces, New Mexico, to PNM’s West Mesa Substation located near Albuquerque, New Mexico. This is the primary delivery point for the Company’s generation entitlement from Four Corners, which is transmitted to the West Mesa Substation over approximately 150 miles of transmission lines owned by PNM.

Greenlee-Newman Line. The Company owns 40% of a 60-mile, 345 kV transmission line between TEP’s Greenlee Substation near Duncan, Arizona to the Hidalgo Substation near Lordsburg, New Mexico, approximately 57% of a 50-mile, 345 kV transmission line between the Hidalgo Substation and the Luna Substation and 100% of an 86-mile, 345 kV transmission line between the Luna Substation and the Newman Power Station. These lines provide an interconnection with TEP for delivery of the Company’s entitlements from Palo Verde and, if necessary, Four Corners.

AMRAD-Eddy County Line. The Company owns 66.7% of a 125-mile, 345 kV transmission line from the AMRAD Substation near Oro Grande, New Mexico, to the Company’s and TNP’s high voltage direct current terminal at the Eddy County Substation near Artesia, New Mexico. This terminal enables the Company to connect its transmission system to that of SPS, providing the Company with access to emergency power from SPS and power markets to the east.

Palo Verde Transmission and Switchyard. The Company owns 18.7% of two 45-mile, 500 kV lines from Palo Verde to the Westwing Substation located to the northwest of Phoenix near Peoria, Arizona

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and 18.7% of a 75-mile, 500 kV line from Palo Verde to the Kyrene Substation located near Tempe, Arizona. These lines provide the Company with a transmission path for delivery of power from Palo Verde. The Company also owns 18.7% of two new 500 kV switchyards connected to the Palo Verde-Kyrene 500 kV line including the Hassayampa switchyard that has been constructed adjacent to the southern edge of the Palo Verde 500 kV switchyard and the Jojoba switchyard that has been constructed approximately 24 miles from Palo Verde. These new switchyards were built to accommodate the addition of new generation and transmission in the Palo Verde area. The cost of constructing the new switchyards has been paid by third-party users.

Environmental Matters

The Company is subject to regulation with respect to air, soil and water quality, solid waste disposal and other environmental matters by federal, state, tribal and local authorities. Those authorities govern current facility operations and have continuing jurisdiction over facility modifications. Failure to comply with these environmental regulatory requirements can result in actions by regulatory agencies or other authorities that might seek to impose on the Company administrative, civil, and/or criminal penalties. In addition, unauthorized releases of pollutants or contaminants into the environment can result in costly cleanup obligations that are subject to enforcement by the regulatory agencies. Environmental regulations can change rapidly and are often difficult to predict. While the Company strives to prepare for and implement changes necessary to comply with changing environmental regulations, substantial expenditures may be required for the Company to comply with such regulations in the future.

The Company analyzes the costs of its obligations arising from environmental matters on an ongoing basis, and believes it has made adequate provision in its financial statements to meet such obligations. As a result of this analysis, the Company has a provision for environmental remediation obligations of approximately $1.2 million as of December 31, 2002, which is related to Clean Water Act compliance. However, unforeseen expenses associated with compliance could have a material adverse effect on the future operations and financial condition of the Company.

The Company is not under any active investigation by the Environmental Protection Agency, the Texas Commission on Environmental Quality, or the New Mexico Environment Department. Furthermore, the Company is not aware of any unresolved liability it would face pursuant to the Comprehensive Environmental Response, Compensation and Liability Act of 1980, also known as the Superfund law.

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Construction Program

Utility construction expenditures reflected in the following table consist primarily of expanding and updating the transmission and distribution systems and the cost of capital improvements and replacements at Palo Verde and other generating facilities, including the replacement of the Palo Verde Unit 2 steam generators and fabrication and shipment for two additional sets of steam generators. Replacement power costs expected to be incurred during replacements of Palo Verde steam generators are not included in construction costs. Preliminary studies indicate that the Company will need additional supply-side and demand-side resources in 2006 to meet increasing load requirements on its system. As a result, on January 30, 2003, the Company released a Request for Proposals (“RFP”) seeking bids to supply 150 MW of additional resources beginning in 2006 and an additional 100 MW beginning in 2009. Responses to the Company’s RFP are due on April 28, 2003.

The Company’s estimated cash construction costs for 2003 through 2006 are approximately $292 million. Actual costs may vary from the construction program estimates shown. Such estimates are reviewed and updated periodically to reflect changed conditions.

Energy Sources

General

The following table summarizes the percentage contribution of nuclear fuel, natural gas, coal and purchased power to the total kWh energy mix of the Company. Energy generated by wind turbines accounted for less than 1% of the total kWh energy mix.

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Allocated fuel and purchased power costs are generally passed through directly to customers in Texas and New Mexico pursuant to applicable regulations. Historical fuel costs and revenues are reconciled periodically in proceedings before the Texas and New Mexico Commissions to determine whether a refund or surcharge based on such historical costs and revenues is necessary. However, from October 1998 to June 2001, a fixed fuel factor was incorporated into the Company’s frozen base rates in New Mexico pursuant to the New Mexico Settlement Agreement. Therefore, there were no fuel reconciliation filings before the New Mexico Commission during that period. See “Regulation – Texas Regulatory Matters” and “– New Mexico Regulatory Matters.”

Nuclear Fuel

The nuclear fuel cycle for Palo Verde consists of the following stages: the mining and milling of uranium ore to produce uranium concentrates; the conversion of the uranium concentrates to uranium hexafluoride (“conversion services”); the enrichment of uranium hexafluoride (“enrichment services”); the fabrication of fuel assemblies (“fabrication services”); the utilization of the fuel assemblies in the reactors; and the storage and disposal of the spent fuel. The Palo Verde Participants have contracts for uranium concentrates and inventory available to meet 69% of Palo Verde’s uranium requirements in 2003. The Palo Verde Participants also have contracts for conversion services and enrichment services to meet 100% of Palo Verde’s conversion and enrichment requirements in 2003. In 2004, the Palo Verde Participants have contracts to meet 100% of enrichment requirements, 87% of conversion requirements and 95% of uranium requirements. At the end of 2002, the Palo Verde Participants selected and approved the vendors to supply the remaining amount of uranium concentrates for 2003 and conversion services and enrichment services for 2004. According to APS, the contracts will be finalized in early 2003. For 2004, a new enriched uranium product contract will commence that will furnish up to 100% of Palo Verde’s operational requirements for uranium concentrates, conversion services and enrichment services through 2008. This new contract could also provide 100% of enrichment services in 2009 and 2010. The Palo Verde Participants have contracts for fabrication services through 2015 for each Palo Verde unit.

Nuclear Fuel Financing. Pursuant to the ANPP Participation Agreement, the Company owns an undivided interest in nuclear fuel purchased in connection with Palo Verde. The Company has available a total of $100 million under a revolving credit facility that provides for both working capital and up to $70 million for the financing of nuclear fuel. At December 31, 2002, approximately $47.2 million had been drawn to finance nuclear fuel. This financing is accomplished through a trust that borrows under the facility to acquire and process the nuclear fuel. The Company is obligated to repay the trust’s borrowings with interest and has secured this obligation with First Mortgage Collateral Series Bonds. In the Company’s financial statements, the assets and liabilities of the trust are reported as assets and liabilities of the Company.

Natural Gas

The Company manages its natural gas requirements through a combination of long-term contracts and market purchases. In 2002, the Company’s natural gas requirements at the Rio Grande Power Station were met with both short-term and long-term natural gas purchases from various suppliers. Interstate gas is delivered under a firm transportation agreement which expires in 2005. The Company anticipates it will continue to purchase natural gas at market prices on a monthly basis for a portion of the fuel needs for the Rio Grande Power Station for the near term. To complement those monthly purchases, the Company has entered into a two-year gas supply contract that began in 2002.

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The Company will continue to evaluate the availability of short-term natural gas supplies versus long-term supplies to maintain a reliable and economical supply for the Rio Grande Power Station.

Natural gas for the Newman and Copper Power Stations was supplied primarily pursuant to an intrastate natural gas contract that became effective January 1, 1997 and was renegotiated for a period of five years ending December 31, 2007. The Company will also continue to evaluate short-term natural gas supplies to maintain a reliable and economical supply for the Newman and Copper Power Stations.

Coal

APS, as operating agent for Four Corners, purchases Four Corners’ coal requirements from a supplier with a long-term lease of coal reserves owned by the Navajo Nation. The coal contract expires in 2004 and can be extended for an additional 15 years. Based upon information from APS, the Company believes that Four Corners has sufficient reserves of coal to meet the plant’s operational requirements for its useful life. APS, on behalf of the Company and the other Four Corners Participants, is in negotiations with the supplier to extend the coal contract through 2016 to coincide with the Four Corners Plant lease with the Navajo Nation.

Purchased Power

To supplement its own generation and operating reserves, the Company engages in firm and non-firm power purchase arrangements which may vary in duration and amount based on evaluation of the Company’s resource needs and the economics of the transactions. The Company purchased 75 MW of firm on-peak energy for 2002 and 25 MW of monthly firm on-peak block energy for April through October 2002. Other purchases of shorter duration were made primarily to replace the Company’s generation resources during planned and unplanned outages.

In 2001, the Company entered into a purchase agreement for firm energy of 53 MW in 2002 and 103 MW in 2003 through 2005. This agreement includes a fuel adjustment clause.

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Operating Statistics

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Regulation

General

In 1999, both the Texas and New Mexico legislatures enacted electric utility industry restructuring laws requiring competition in certain functions of the industry and ultimately in the Company’s service area. Competition in New Mexico was scheduled to begin on January 1, 2002 under the New Mexico Electric Utility Industry Restructuring Act of 1999. On March 8, 2001, however, the New Mexico Restructuring Act was amended to delay the start of competition for five years until January 1, 2007, and on February 28, 2003, the New Mexico Senate passed Senate Bill 718 to repeal the New Mexico Restructuring Act. The Company cannot predict whether this pending legislation will pass the New Mexico House of Representatives and be signed into law by the Governor of New Mexico. In Texas, the Company is exempt from the requirements of Chapter 39 of the Public Utility Regulatory Act (“PURA”), including utility restructuring and retail competition, until the expiration of the Freeze Period in August 2005.

The Company continues to prepare to comply with these restructuring laws and other regulatory, economic and technological changes occurring throughout the industry. Deregulation of the production of electricity and related services and increasing customer demand for lower priced electricity and other energy services have accelerated the industry’s movement toward more competitive pricing and cost structures. Those competitive pressures could result in the loss of customers and diminish the ability of the Company to fully recover its investment in generation assets. In January 2002, competition was initiated in some parts of Texas. As a result, the Company may face increasing pressure on its retail rates and its rate freeze under the Texas Rate Stipulation. The Company’s results of operations and cash flows may be adversely affected if it cannot maintain its current retail rates.

Federal Regulatory Matters

Federal Energy Regulatory Commission. The Company is subject to regulation by the FERC in certain matters, including rates for wholesale power sales, transmission of electric power and the issuance of securities.

Since February 2002, the FERC has been conducting an investigation into potential manipulation of electricity prices in the western United States during 2000 and 2001. On August 13, 2002, the FERC initiated a Federal Power Act (“FPA”) investigation (Docket No. EL02-113) into the Company’s wholesale power trading in the western United States during 2000 and 2001 to determine whether the Company and Enron engaged in misconduct and, if so, to determine potential remedies. Depending on its findings, the FERC could seek to revoke the Company’s market-based rate authority or order refunds or disgorgements. The Company’s revenue from economy sales in the western United States during 2000 and 2001 was approximately $100 million, and net income from these sales after taxes and margin sharing with retail customers was approximately $37 million. Intervenors in the proceeding include the California Attorney General, the California Public Utilities Commission, the California Independent System Operator, Pacific Gas and Electric, the cities of Burbank, California and Tacoma, Washington and others with similar interests.

On December 5, 2002, the Company announced that it had reached a settlement with the FERC Trial Staff. The settlement resolves all issues between the Company and the Trial Staff. In February 2003, the Company also reached a settlement with the California Attorney General and the

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California Electricity Oversight Board. In addition, the California Public Utilities Commission and Pacific Gas and Electric agreed not to oppose the settlements. Under the terms of the settlements, the Company agrees to refund a total of $15.5 million of revenues it earned on wholesale power transactions. This amount has been accrued as a liability as of December 31, 2002. The Company also agrees to make wholesale sales pursuant to its cost of service rate authority rather than its market-based rate authority from December 1, 2002 through December 31, 2004. During 2002, economy sales prices were below the rates the Company would be allowed to charge under its cost of service tariffs.

In its December 5 testimony, the FERC Trial Staff asserts that the Company violated Sections 205 and 206 of the FPA by not filing a tariff with the FERC to collect monies with respect to its parking and lending services and its supplemental services provided for Enron and in not offering these services on an open access, non-discriminatory basis. The Trial Staff also contends that the Company violated Section 203 of the FPA by allegedly ceding control over its generation to Enron when Enron ran the Company’s real-time marketing desk and by entering into an agreement with Enron whereby Enron received valuable information from the Company as well as compensation based on calculated cost savings. Additionally, the Trial Staff maintains that the Company engaged in activities that it describes as “ricochet” or “megawatt laundering.” The Trial Staff calculates the Company earned approximately $21 million on an after-tax basis from sales above the Company’s cost-based rate authority. Finally, the Trial Staff submits that the Company may have violated FERC Order No. 888 open access transmission requirements by not posting generation swap transactions it performed with Enron and by not filing tariffs for parking, lending and hubbing services performed for Enron. In the interest of settlement, the parties to the settlement agreed to make no determination regarding any violation of legal provisions. The settlements are subject to FERC approval, and in the event the FERC does not approve the settlements, neither the Company, the Trial Staff nor the settling intervenors will be bound by their terms.

The Company has denied and will continue to deny the allegations made by FERC Trial Staff and the intervenors. The City of Tacoma, Washington filed testimony on December 19, 2002 and its witness concurred with the Trial Staff’s findings and the proposed remedy regarding the Company. The Company’s direct testimony, filed February 4, 2003, and rebuttal testimony, filed March 4, 2003, support the settlements and respond to issues raised by the Trial Staff and intervenors. The Company’s testimony asserts that it has not violated the FPA or any FERC regulation. The hearing is set to begin April 1, 2003.

RTOs. On December 15, 1999, the FERC approved its final rule (“Order 2000”) on Regional Transmission Organizations (“RTOs”). Order 2000 strongly encourages, but does not require, public utilities to form and join RTOs. Order 2000 also proposes RTO startup by December 15, 2001. The Company is an active participant in the development of WestConnect, formerly known as the Desert Southwest Transmission and Reliability Operator. The Company believes WestConnect will qualify as an RTO under Order 2000. The Company intends, subject to the resolution of outstanding issues, to participate in WestConnect. As a participating transmission owner, the Company will transfer operational authority of its transmission system to WestConnect subject to receiving any necessary regulatory approvals. The WestConnect proposal was submitted to the FERC on October 15, 2000. On October 10, 2002, FERC issued an order indicating that the WestConnect proposal satisfied, or with certain modifications would satisfy, the FERC requirements for an RTO under Order 2000. WestConnect will continue to work with the FERC and two other proposed RTOs in the west to achieve seamless operations.

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Department of Energy. The DOE regulates the Company’s exports of power to CFE in Mexico pursuant to a license granted by the DOE and a presidential permit. The DOE has determined that all such exports over international transmission lines shall be made in accordance with Order No. 888, which established the FERC rules for open access.

The DOE is authorized to assess operators of nuclear generating facilities a share of the costs of decommissioning the DOE’s uranium enrichment facilities and for the ultimate costs of disposal of spent nuclear fuel. See “Facilities – Palo Verde Station – Spent Fuel Storage” for discussion of spent fuel storage and disposal costs.

Nuclear Regulatory Commission. The NRC has jurisdiction over the Company’s licenses for Palo Verde and regulates the operation of nuclear generating stations to protect the health and safety of the public from radiation hazards. The NRC also has the authority to conduct environmental reviews pursuant to the National Environmental Policy Act.

Texas Regulatory Matters

The rates and services of the Company are regulated in Texas municipalities by those municipalities and in unincorporated areas by the Texas Commission. The largest municipality in the Company’s service area is the City of El Paso. The Texas Commission has exclusive appellate jurisdiction to review municipal orders and ordinances regarding rates and services in Texas and jurisdiction over certain other activities of the Company. The decisions of the Texas Commission are subject to judicial review.

Deregulation. PURA Chapter 39 required an investor-owned electric utility to separate its power generation activities from its transmission and distribution activities by January 1, 2002, and on that date, retail competition was instituted in some parts of Texas. In the case of the Company, however, the exemption from PURA Chapter 39 specifically recognized and preserved the Company’s Texas Rate Stipulation and Texas Settlement Agreement by, among other things, exempting the Company’s Texas service area from retail competition until the end of the Freeze Period. At the end of the Freeze Period, the Company will be subject to all the applicable provisions of the law. At that time, the Company will be permitted to continue to recover nuclear decommissioning costs through a non-bypassable customer charge in its distribution rates. Under its exemption from PURA Chapter 39, however, the Company will have no claim for stranded cost recovery. (Stated simply, stranded costs are the positive difference, if any, between the book value of electric generating assets, including long-term purchase power contracts, and the market value of those assets). The Company believes that its continued ability to provide bundled electric service at current rates in its Texas service area will allow the Company to collect substantially all of its Texas jurisdictional stranded costs because (i) the Company revalued its utility plant under fresh start accounting in 1996 so that the generation assets would reflect projected market values in a deregulated environment and (ii) the Company does not have power purchase contracts that extend beyond 2005.

Although the Company is not subject to the requirements of PURA Chapter 39 until the expiration of the Freeze Period, the Company sought Texas Commission approval of the Company’s corporate restructuring in anticipation of complying with the restructuring requirements of the New Mexico Restructuring Act. In December 2000, the Texas Commission approved the Company’s corporate restructuring plan. However, the amended New Mexico Restructuring Act now prohibits the separation of the Company’s generation activities from its transmission and distribution activities before

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September 1, 2005. Both Texas and New Mexico Legislatures will be in session in 2003, and either or both could amend their respective restructuring laws during these sessions. However, the Company cannot predict whether any changes to the current restructuring laws will be made, and how or when such changes, if any, would be implemented.

Texas Rate Stipulation and Texas Settlement Agreement. The Texas Rate Stipulation and Texas Settlement Agreement govern the Company’s rates for its Texas customers but do not deprive the Texas regulatory authorities of their jurisdiction over the Company during the Freeze Period. However, the Texas Commission determined that the rate freeze is in the public interest and results in just and reasonable rates. Further, the signatories to the Texas Rate Stipulation (other than the Texas Office of Public Utility Counsel and the State of Texas) agreed not to seek to initiate an inquiry into the reasonableness of the Company’s rates during the Freeze Period and to support the Company’s entitlement to rates at the freeze level throughout the Freeze Period. During the Freeze Period, the Company is precluded from seeking base rate increases in Texas, even in the event of increased operating or capital costs. In the event of a merger, the parties to the Texas Rate Stipulation retain all rights provided in the Texas Rate Stipulation, the right to participate as a party in any proceeding related to the merger, and the right to pursue a reduction in rates below the freeze level to the extent of post-merger synergy savings.

Fuel. Although the Company’s base rates are frozen in Texas, pursuant to Texas Commission rules and the Texas Rate Stipulation, the Company can request adjustments to its fuel factor to more accurately reflect projected energy costs associated with the provision of electricity as well as seek recovery of past undercollections of fuel revenues.

In October 2001, the Texas Commission approved the Texas Fuel Settlement between the Company and the parties which had intervened, including the City of El Paso, which increased the Texas fuel factor to $0.02494 per kWh (an increase of $0.00308 per kWh). This factor was implemented on an interim basis in April 2001. The Texas Fuel Settlement also provides for the surcharge of underrecovered fuel costs as of December 31, 2000 of approximately $15 million plus interest over an 18-month period. The fuel surcharge was implemented on an interim basis beginning with the first billing cycle in June 2001. The Company terminated its interim fuel surcharge with the last billing cycle in November 2002 as expected, having collected $17.5 million, or 99% of the $17.7 million it had anticipated would be collected over the 18-month period.

On July 1, 2002, the Company filed a petition with the Texas Commission to reconcile the Company’s fuel and purchased power expenses and associated revenues for the three-year period January 1, 1999 through December 31, 2001. This filing was made pursuant to Texas Commission rules, which require companies to submit a fuel reconciliation at least every three years. Among other things, the Company’s petition included a request for: (i) a reconciliation of the Company’s Texas jurisdiction eligible fuel costs for the period of $277.0 million and fuel factor revenues of $268.9 million; (ii) recovery of Palo Verde performance rewards of $21.6 million, including interest, for achieving a three period average capacity factor of 89.8% (the three periods used for this reward amount, each of which consists of a three-year rolling average, are the periods ended in 1998, 1999 and 2000) which, pursuant to the Texas Fuel Settlement, the Texas Commission shall treat as reconciled and (iii) authority to recover its net underrecovered fuel expenses and Palo Verde performance rewards, including interest, through a surcharge which would not overlap or exceed the interim surcharge.

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The Company previously agreed to contribute 50% of the Palo Verde performance rewards to fund programs for bill payment assistance and demand side management programs in its Texas service territory. The Texas Commission staff, local regulatory authorities such as the City of El Paso and customers are entitled to intervene in a fuel reconciliation proceeding and to challenge the prudence of fuel and purchased power expenses. The Company anticipates that it will take nine to twelve months to receive a final order from the Texas Commission. Because of the length of time necessary to conclude the reconciliation proceeding and to subsequently collect the underrecovered amount, the Company has classified as a non-current asset approximately $12.4 million of underrecovered fuel expense subject to the reconciliation proceeding.

Palo Verde Performance Standards. The Texas Commission established performance standards for the operation of Palo Verde, pursuant to which each Palo Verde unit is evaluated annually to determine whether its three-year rolling average capacity factor entitles the Company to a reward or subjects it to a penalty. The capacity factor is calculated as the ratio of actual generation to maximum possible generation. If the capacity factor, as measured on a station-wide basis for any consecutive 24-month period, should fall below 35%, the Texas Commission can also reconsider the rate treatment of Palo Verde, regardless of the provisions of the Texas Rate Stipulation and the Texas Settlement Agreement. The removal of Palo Verde from rate base could have a significant negative impact on the Company’s revenues and financial condition. Under the performance standards as modified by the Texas Fuel Settlement, the Company has calculated the performance awards for the reporting periods ending in 2001 and 2002 to be approximately $1.1 million and $1.3 million, respectively. These rewards will be included, along with energy costs incurred and revenues billed, as part of the Texas Commission’s review during a future periodic fuel reconciliation proceeding as discussed above. Performance rewards are not recorded on the Company’s books until the Texas Commission has ordered a final determination in a fuel proceeding. Performance penalties are recorded when assessed as probable by the Company.

New Mexico Regulatory Matters

The New Mexico Commission has jurisdiction over the Company’s rates and services in New Mexico and over certain other activities of the Company, including prior approval of the issuance, assumption or guarantee of securities. The New Mexico Commission’s decisions are subject to judicial review. The largest city in the Company’s New Mexico service territory is Las Cruces.

Deregulation. In March 2001, the New Mexico Legislature amended the New Mexico Restructuring Act to postpone deregulation in New Mexico until January 1, 2007, and to prohibit the separation of a utility’s transmission and distribution activities from its existing generation activities prior to September 1, 2005. The amended New Mexico Restructuring Act permits utilities to form holding companies subject to New Mexico approval with conditions. It also allows the utility, until corporate separation occurs, to participate in unregulated generation activities if the generation is not intended to serve New Mexico retail customers.

The amended New Mexico Restructuring Act prohibiting the separation of the Company’s generation activities from its transmission and distribution activities prior to September 1, 2005 may conflict with the Texas Restructuring Law requiring separation of those activities after the expiration of the Freeze Period in August 2005. The Company anticipates that it will make a filing with the New Mexico Commission in 2004 requesting approval to separate the Company’s generation activities

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from its transmission and distribution activities to allow the Company to restructure in order to comply with Texas restructuring requirements.

On February 28, 2003, the New Mexico Senate passed Senate Bill 718 to repeal the New Mexico Restructuring Act. The Company cannot predict whether such legislation will pass the New Mexico House of Representatives and be signed into law by the Governor of New Mexico.

Fuel. The New Mexico Settlement Agreement approved by the New Mexico Commission in September 1998 eliminated the then existing fuel factor of $0.01949 per kWh by incorporating it into frozen base rates. Accordingly, the Company was required to absorb any increases in fuel and purchased power (“energy”) expenses related to its New Mexico retail customers until new rates were implemented subsequent to the end of the rate freeze on April 30, 2001. The average energy expenses incurred for New Mexico jurisdictional customers exceeded this fuel factor by a substantial amount. Therefore, on April 23, 2001, the Company filed a petition with the New Mexico Commission proposing a settlement that would implement a new incremental fixed fuel and purchased power factor (“fuel factor”) effective June 15, 2001, while leaving the existing $0.01949 fuel factor as part of the still frozen base rates, and reinstate for a two-year period a fuel and purchased power adjustment clause in lieu of a base rate increase (the “New Mexico Fuel Factor Agreement”). The New Mexico Commission entered its final order on January 8, 2002 implementing the New Mexico Fuel Factor Agreement and setting an initial incremental fixed fuel factor of $0.01501 per kWh.

On February 12, 2002, the Company filed a petition with the New Mexico Commission for an incremental fuel factor decrease to $0.00420 per kWh. The New Mexico Commission issued an order approving that decrease on February 19, 2002. This new incremental fuel factor was implemented as of the first billing cycle in March 2002.

At the end of the two-year Freeze Period in June 2003, the Company will be required to file (i) a reconciliation of fuel revenues and expenses and (ii) a base rate case. At that time the New Mexico fuel factor will be reset to an amount equal to the actual energy expenses for the first six months of 2003. This reset fuel factor will remain in effect until the completion of the rate case which could take ten to twelve months to prosecute.

Sales for Resale

During 2002, the Company provided IID with 100 MW of firm capacity and associated energy and 50 MW of system contingent capacity and associated energy pursuant to a 17-year agreement which expired on April 30, 2002. The Company also provided TNP in 2002 with up to 75 MW of firm capacity and associated energy pursuant to an agreement that expired on December 31, 2002. The Company’s sales for resale in 2002 included sales of $15.4 million and $31.5 million to IID and TNP, respectively, under contracts which expired in 2002 and which have not been renewed. The Company also sold 100 MW of interruptible energy to CFE during the months of June and July 2002.

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Power Sales Contracts

As of March 7, 2003, the Company had entered into the following significant agreements with various counterparties for forward firm sales of electricity:

The Company also has an agreement with a counterparty for power exchanges under which the Company received 80 MW of on-peak capacity and associated energy during 2002 at the Eddy County tie and concurrently delivered the same amount at Palo Verde and/or Four Corners. The on-peak exchange amount decreases to 30 MW for 2003 through 2005. The agreement also gives the counterparty the option to deliver up to 133 MW of off-peak capacity and associated energy to the Company at the Eddy County tie from 2002 through 2005 in exchange for the same amount of energy concurrently delivered by the Company at Palo Verde and/or Four Corners. The Company will receive a guaranteed margin on any energy exchanged under the off-peak agreement. See “Purchased Power.”

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Executive Officers of the Registrant

The executive officers of the Company as of March 7, 2003, were as follows:

The executive officers of the Company are elected annually and serve at the discretion of the Board of Directors.

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Item 2. Properties

The principal properties of the Company are described in Item 1, “Business,” and such descriptions are incorporated herein by reference. Transmission lines are located either on private rights-of-way, easements or on streets or highways by public consent. See Part II, Item 8, “Financial Statements and Supplementary Data – Note F of Notes to Consolidated Financial Statements” for information regarding encumbrances against the principal properties of the Company.

In addition, the Company leases executive and administrative offices in El Paso, Texas. See Part II, Item 8, “Financial Statements and Supplementary Data – Note H of Notes to Consolidated Financial Statements” for information regarding the leased property.

Item 3. Legal Proceedings

The Company is a party to various legal actions. In many of these matters, the Company has excess casualty liability insurance that covers the various claims, actions and complaints. Based upon a review of these claims and applicable insurance coverage, the Company believes that none of these claims will have a material adverse effect on the financial position, results of operations and cash flows of the Company.

On January 16, 2003, the Company was served with a complaint on behalf of a purported class of shareholders alleging violations of the federal securities laws (Roth v. El Paso Electric Company, et al., No. EP-03-CA-0004). The complaint was filed in the El Paso Division of the United States District Court for the Western District of Texas by a holder of 100 common shares of the Company. The suit seeks undisclosed compensatory damages for the class as well as costs and attorneys’ fees. The complaint asserts violations of the Securities Exchange Act of 1934. Among other things, the complaint alleges that the Company improperly benefited from wholesale power sales into the western United States through its power marketing agreement with Enron during 2000 and 2001 and that the Company’s failure to properly disclose this agreement artificially inflated the Company’s stock price during the same period. The allegations arise out of the FERC investigation of the power markets in the western United States during 2000 and 2001. The Company and the Trial Staff of the FERC reached a settlement of the FERC investigation on December 5, 2002. The Company and the California Attorney General and the California Electricity Oversight Board reached a supplemental agreement on February 13, 2003, which the California Public Utilities Commission and Pacific Gas and Electric Company agreed not to oppose. The settlements are subject to FERC approval. The Company believes the lawsuit is without merit and intends to defend itself vigorously. On February 3, 2003, the parties filed an agreed motion to extend the time for the Defendants to file an answer or otherwise respond to the lawsuit until the Court appoints a lead Plaintiff and the lead Plaintiff files a consolidated complaint. No hearings have been set. The Company is unable to predict the outcome of this case.

On February 10, 2003, the Company received a letter initiating a legal proceeding known as a shareholder derivative action. The letter, written by a Pennsylvania law firm on behalf of the holder of approximately 200 shares of common stock of the Company (the “shareholder”), requests that the Company commence a lawsuit against each member of the Board of Directors to recover damages allegedly sustained by the Company as a result of alleged breaches of fiduciary duties by the Board. The shareholder contends that, from 1997 to 2002, the Board knowingly caused or allowed the Company to

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participate in improper transactions with Enron Corporation and certain of its subsidiaries. The allegations appear to duplicate factual questions first raised by the FERC in an investigation of the power markets in the western United States during 2000 and 2001. As noted above, the Company reached a settlement of the FERC investigation with the FERC Trial Staff on December 5, 2002 and with the principal California intervenors in the FERC investigation. In accordance with Texas law, the Company will conduct an independent inquiry to determine whether a lawsuit against the Board is in the best interests of the Company. The Company is unable to predict the outcome of this case.

The Company’s federal income tax returns for the years 1996 through 1998 have been examined by the IRS. On October 3, 2001, the Company received the IRS notice of proposed deficiency. The primary audit adjustments proposed by the IRS related to (i) whether the Company was entitled to deduct payments made on emergence from Chapter 11 bankruptcy proceedings related to Palo Verde and (ii) the settlement of litigation in 1997 concerning a terminated merger during the Company’s bankruptcy. The Company has protested the audit adjustments through administrative appeals and believes that its treatment of the payments is supported by substantial legal authority. In November 2002, the Company received notice through the administrative appeals process that the second issue described above had been conceded by the IRS appeals officer. Even though the IRS appeals officer has, at present, conceded this issue, this concession will not be final until the administrative appeals process is complete. In the event that the IRS prevails, the resulting income tax and interest payments could be material to the Company’s financial position, results of operations and cash flows.

Item 4. Submission of Matters to a Vote of Security Holders

Not applicable.

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PART II

Item 5. Market for Registrant’s Common Equity and Related Stockholder Matters

The Company’s common stock began trading on the New York Stock Exchange on December 4, 2002, under the symbol “EE.” Prior to that date, the Company’s common stock traded on the American Stock Exchange. The high, low and close sales prices for the Company’s common stock, as reported in the consolidated reporting system of the New York Stock Exchange and the American Stock Exchange for the periods indicated below were as follows:

As of March 7, 2003, there were 4,808 holders of record of the Company’s common stock. The Company does not anticipate paying dividends on its common stock in the near-term. The Company intends to continue its deleveraging and stock repurchase programs with the goal of improving its capital structure.

The Company’s Board of Directors previously approved three stock repurchase programs allowing the Company to purchase up to fifteen million of its outstanding shares of common stock. As of March 7, 2003, the Company had repurchased 13,163,129 shares of common stock under these programs for approximately $149.4 million, including commissions. The Company may continue making purchases of its stock at open market prices and may engage in private transactions, where appropriate. Any repurchased shares will be available for issuance under employee benefit and stock option plans, or may be retired.

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Item 6. Selected Financial Data

As of and for the following periods (in thousands except for share data):

The selected financial data should be read in conjunction with Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and Item 8, “Financial Statements and Supplementary Data.”

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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Statements in this document, other than statements of historical information, are forward-looking statements that are made pursuant to the safe harbor provisions of the Private Securities Litigation Reform Act of 1995. Such forward-looking statements, as well as other oral and written forward-looking statements made by or on behalf of the Company from time to time, including statements contained in the Company’s filings with the Securities and Exchange Commission and its reports to shareholders, involve known and unknown risks and other factors which may cause the Company’s actual results in future periods to differ materially from those expressed in any forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to: (i) increased prices for fuel and purchased power and the possibility that regulators may not permit the Company to pass through all such increased costs to customers, (ii) fluctuations in wholesale margins due to uncertainty in the wholesale power market, (iii) unanticipated increased costs associated with scheduled and unscheduled outages, (iv) the cost of replacing steam generators and other unexpected costs at Palo Verde, (v) the costs of legal defense, possible refunds or disgorgements, or loss of market-based authority which may accrue as the result of ongoing FERC proceedings, (vi) deregulation of the electric utility industry and (vii) other factors discussed below under the headings “Summary of Critical Accounting Policies and Estimates,” “Overview” and “Liquidity and Capital Resources.” The Company’s filings are available from the Securities and Exchange Commission or may be obtained through the Company’s website, www.epelectric.com. Any such forward-looking statement is qualified by reference to these risks and factors. The Company cautions that these risks and factors are not exclusive. The Company does not undertake to update any forward-looking statement that may be made from time to time by or on behalf of the Company except as required by law.

Summary of Critical Accounting Policies and Estimates

Note A to the Consolidated Financial Statements contains a summary of the significant accounting policies that the Company uses. The preparation of these statements requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and related notes for the periods presented and actual results could differ from those estimates. Critical accounting estimates, which are both important to the portrayal of the Company’s financial condition and results of operations and which require complex, subjective judgments, include the following:

Value of Net Utility Plant in Service

In 1996, when it emerged from bankruptcy, the Company recast its financial statements by applying fresh-start reporting in accordance with Statement of Position 90-7 “Financial Reporting by Entities in Reorganization Under the Bankruptcy Code.” In this process, the Company attributed value to its integrated utility system, including its generation assets, after it had established the value of its pro forma capital structure based on management’s estimates of future operating results. The Company

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valued its generation assets such that the depreciated value of its generation assets would be approximately equal to their estimated fair value at the end of the Freeze Period. This is important because at the beginning of retail competition in Texas and New Mexico, the Company will no longer be permitted to recover in rates any “stranded costs”, that is, the difference between the book value and the market value of its electric generation assets. If at any time the Company determines that estimated, undiscounted future net cash flows from the operations of the generation assets are not sufficient to recover their net book value then it will be required to write down the value of these assets to their fair values. Any such write down would be charged to earnings. The Company currently believes that its rates are sufficient to collect before 2005 substantially all costs that would otherwise be “stranded” under relevant laws in Texas and New Mexico and that future net cash flows after 2005 from the generating assets will be sufficient to recover their net book values.

Decommissioning Costs

Pursuant to the ANPP Participant Agreement and federal law, the Company must fund its share of the estimated costs to decommission Palo Verde Units 1, 2, and 3 and associated common areas. The Company and other Palo Verde Participants rely upon decommissioning cost studies and make interest rate, rate of return and inflation projections to determine funding requirements and estimate liabilities related to decommissioning. Every third year, outside engineers perform a study to estimate decommissioning costs associated with Palo Verde Units 1, 2 and 3 and associated common areas. The Company funds its share of those estimated costs through professionally managed investment trust accounts. Management must make assumptions about future investment returns and future cost escalations in order to determine the amounts with which to fund the trusts. If actual decommissioning costs exceed estimates, the Company would incur additional expenses related to decommissioning. Further, if the rates of return earned by the trusts fail to meet expectations, the Company will be required to increase its funding to the decommissioning trust accounts. Although the Company cannot predict the results of future studies, the Company believes that the liability it has recorded for its decommissioning costs will be adequate to provide for the Company’s share of the costs. The Company believes that its current annual funding levels of the decommissioning trust will adequately provide for the cash requirements associated with decommissioning. Historically, regulated utilities such as the Company have been permitted to collect in rates the costs of nuclear decommissioning. Under deregulation legislation in both Texas and New Mexico, the Company expects to continue to be able to collect from customers the costs of decommissioning.

Collection of Fuel Expense

As a regulated entity, the Company’s fuel and purchased power expenses are passed through directly to its regulated customers. These costs are then subject to a prudency review of its fuel and purchased power costs by the Texas and New Mexico Commissions. In general, if the Texas and New Mexico Commissions find that the fuel and purchased power expenses were reasonably incurred, the Company may recover those expenses from its customers. Until those periodic reviews are completed, however, management must rely upon projections related to fuel and purchased power prices in order to estimate fuel revenues. When prices exceed management’s estimates, the Company undercollects fuel and purchased power expenses from its customers. The Company must then petition its regulators to reconcile its actual costs to actual revenues received from customers. Historically, regulators have allowed the Company to recover most of its fuel and purchased power-related expenses. If energy costs were deemed unreasonably incurred and regulators were to disallow recovery of these costs, however, the Company would incur a loss to the extent of the disallowance.

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Future Pension and Other Postretirement Obligations

In accounting for its retirement plans and other postretirement benefits, the Company makes assumptions regarding the valuation of benefit obligations and the performance of plan assets. The accounting for retirement plans and other postretirement obligations allows for a smoothed recognition of changes in benefit obligations and plan performance over the service lives of the employees who benefit under the plans. The primary assumptions are discount rate, expected return on plan assets, rate of compensation increase and health care cost inflation. A change in any of these assumptions could have a significant impact on future costs, which may be reflected as an increase or decrease in net income in the period, or on the amount of related liabilities reflected on the Company’s consolidated balance sheet.

Reserves for Tax Dispute

The IRS has disputed whether the Company was entitled to deduct certain payments made in 1996 related to Palo Verde and its treatment of a litigation settlement in 1997 related to a terminated merger agreement. If the IRS prevails on the former issue, the Company would be required to include the previously deducted amounts in the tax basis of Palo Verde and deduct them over its useful life. This would not have a material impact on reported net income but would result in a significant cash payment, which would be offset by reduced future tax liability as the increased tax basis is deducted. An adverse resolution of the second issue would lead to the recognition of additional revenue in the Company’s tax return with no related tax benefits and could result in a material amount of additional tax. In November 2002, the Company received notice through the administrative appeals process that the second issue described above had been conceded by the IRS appeals officer. Even though the IRS appeals officer has, at present, conceded this issue, this concession will not be final until the administrative appeals process is complete. The Company has established, and periodically reviews and re-evaluates, an estimated contingent tax liability on its consolidated balance sheet to provide for the possibility of adverse outcomes in tax proceedings. Although the ultimate outcome cannot be predicted with certainty, and while the contingent tax reserve may not in fact be sufficient, the Company believes that the amount at December 31, 2002 adequately provides for any additional tax that may be due.

Overview

El Paso Electric Company is an electric utility that serves retail customers in west Texas and southern New Mexico and wholesale customers in the states of Texas and New Mexico and in the Republic of Mexico. The Company owns or has substantial ownership interests in six electrical generating facilities providing it with a total capacity of approximately 1,500 MW. The Company’s energy sources consist of nuclear fuel, natural gas, coal, purchased power and wind. The Company owns or has significant ownership interests in four major 345 kV transmission lines and three 500 kV transmission lines to provide power from Palo Verde and Four Corners, and owns the distribution network within its retail service territory. The Company is subject to regulation by the Texas and New Mexico Commissions and, with respect to wholesale power sales, transmission of electric power and the issuance of securities, by the FERC.

The Company faces a number of risks and challenges that could negatively impact its operations and financial results. The most significant of these risks and challenges are the deregulation of the electric utility industry, the possibility of increased costs, especially from Palo Verde, the Company’s high

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level of debt, costs and expenses or judgments related to the FERC proceedings and the possible write-off of the costs of the Company’s CIS project.

The electric utility industry in general and the Company in particular are facing significant challenges and increased competition as a result of changes in federal provisions relating to third-party transmission services and independent power production, as well as changes in state laws and regulatory provisions relating to wholesale and retail service. In 1999, both Texas and New Mexico passed industry deregulation legislation requiring the Company to separate its transmission and distribution functions, which will remain regulated, from its power generation and energy services businesses, which will operate in a competitive market in the future. New Mexico subsequently amended its deregulation law to delay the implementation date. In February 2003, a bill was introduced to repeal the New Mexico Restructuring Act. In Texas, the Company’s service territory has not yet been deregulated, but the Company is preparing for competition at the end of the Rate Freeze in 2005. There is substantial uncertainty about both the regulatory framework and market conditions that will exist at that time and the Company may incur substantial preparatory, restructuring and other costs that may not ultimately be recoverable. There can be no assurance that deregulation will not adversely affect the future operations, cash flows and financial condition of the Company.

The changing regulatory environment and the advent of unregulated power production have created a substantial risk that the Company will lose important customers. The Company’s wholesale and large retail customers already have, in varying degrees, additional alternate sources of economical power, including co-generation of electric power. Historically, the Company has lost certain large retail customers to self generation and/or co-generation and has seen reductions in wholesale sales due to new sources of generation. If the Company loses a significant portion of its retail customer base or wholesale sales, the Company may not be able to replace such revenues through either the addition of new customers or an increase in rates to remaining customers.

Another risk to the Company is potential increased costs, including the risk of additional or unanticipated costs at Palo Verde resulting from (i) increases in operation and maintenance expenses; (ii) the replacement of steam generators; (iii) an extended outage of any of the Palo Verde units; (iv) increases in estimates of decommissioning costs; (v) the storage of radioactive waste, including spent nuclear fuel; (vi) insolvency of other Palo Verde Participants and (vii) compliance with the various requirements and regulations governing commercial nuclear generating stations. At the same time, the Company’s retail base rates in Texas are effectively capped through a rate freeze ending in August 2005. Additionally, upon initiation of competition, there may be competitive pressure on the Company’s power generation rates which could reduce its profitability. The Company cannot assure that its revenues will be sufficient to recover any increased costs, including any increased costs in connection with Palo Verde or other operations, whether as a result of inflation, changes in tax laws or regulatory requirements, or other causes.

Since February 2002, the FERC has been conducting an investigation into potential manipulation of electricity prices in the western United States during 2000 and 2001. On August 13, 2002, the FERC initiated an investigation into the Company’s wholesale power trading in the western United States during 2000 and 2001. On December 5, 2002, the Company announced that it had reached a settlement with the FERC Trial Staff. In February 2003, the Company also reached a settlement with the most significant intervenors. Under the terms of the settlements, the Company agreed to refund a total of $15.5 million of revenues it earned on wholesale power transactions.

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In July 2002, the Company suspended work on its CIS project to perform an assessment of the project and of alternatives to completion of the project. This assessment includes analyzing the continuing changes in the billing requirements as a result of deregulation and the impact the potential delays in the implementation of deregulation may have on the Company and the associated billing requirements. As of December 31, 2002, the Company has capitalized $17.7 million on the CIS project. If, as a result of this assessment, any portion of the amounts that have been capitalized to date to implement a new CIS system are deemed impaired or if the Company abandons the project, the Company would recognize a charge against income in the period such impairment is identified or the project is abandoned and the effect on the Company’s financial results could be material.

Liquidity and Capital Resources

The Company’s principal liquidity requirements in the near-term are expected to consist of interest and principal payments on the Company’s indebtedness, operating and capital expenditures related to the Company’s generating facilities and transmission and distribution systems, and refunds related to sales made in western power markets in 2000 and 2001. See Part I, Item 1, “Business – Regulation – FERC Regulatory Matters.” The Company expects that cash flows from operations will be sufficient for such purposes.

Long-term debt and financing obligations totaling $466.2 million are scheduled to mature or are subject to remarketing between January 2003 and February 2006. The Company expects that certain of these obligations including certain first mortgage bonds and the pollution control bonds totaling $379.3 million and the $100 million revolving credit facility, which as of December 31, 2002 approximately $47.2 million had been drawn for nuclear fuel purchases, will be refinanced through the capital markets. The Company’s ability to access capital markets may be adversely affected by uncertainties related to operating in a competitive energy market, tight credit markets and debt rating agency actions.

Long-term capital requirements of the Company will consist primarily of construction of electric utility plant and the payment of interest on and retirement and refinancing of debt. Utility construction expenditures will consist primarily of expanding and updating the transmission and distribution systems, possible addition of new generation, and the cost of capital improvements and replacements at Palo Verde and other generating facilities, including the replacement of the Palo Verde steam generators. See Part I, Item 1, “Business – Construction Program.”

During 2002, 2001 and 2000, the Company utilized $96.6 million, $128.0 million and $93.6 million, respectively, of federal tax loss carryforwards. The Company anticipates that existing federal tax loss carryforwards will be fully utilized in 2003 and after that date the Company’s cash flow requirements are expected to include greater amounts of cash for income taxes than has existed in recent years.

As a result of the recent declines in the financial markets, the Company anticipates its expenses and cash flow requirements associated with its retirement plans and other postretirement benefit plan and its cash flow requirements related to contributions to the decommissioning trust funds will increase as compared to the related expenses and cash flow requirements of recent years. Although the Company made an additional deposit of $4.7 million into the decommissioning trust funds in January 2003, the Company has not yet determined the total extent of these increased expenses and cash flow requirements.

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As of December 31, 2002, the Company had approximately $75.1 million in cash and cash equivalents, an increase of $47.1 million from the December 31, 2001 balance of $28.0 million. The $100 million revolving credit facility also provides up to $70 million for nuclear fuel purchases. Any amounts not borrowed for nuclear fuel purchases may be borrowed by the Company for working capital needs. In January 2002, the revolving credit facility was renewed for a three-year term. As of December 31, 2002, approximately $47.2 million had been drawn for nuclear fuel purchases. No amounts are currently outstanding on this facility for working capital needs.

The Company has a relatively high debt to capitalization ratio and significant debt service obligations. Due to the Texas Rate Stipulation, the Texas Settlement Agreement, and competitive pressures, the Company does not expect to be able to raise its base rates in Texas in the event of increases in non-fuel costs or loss of revenues. See Part I, Item 1, “Business – Regulation – Texas Regulatory Matters.”

The Company has significantly reduced its long-term debt since its emergence from bankruptcy in 1996. From June 1, 1996 through March 7, 2003, the Company repurchased approximately $443.8 million of first mortgage bonds with internally generated cash as part of a deleveraging program and repaid the remaining $36.0 million, $34.6 million and $36.1 million of Series A, Series B and Series C First Mortgage Bonds at their maturities in February 1999, May 2001 and February 2003, respectively, which has combined to reduce the Company’s annual interest expense by approximately $44.6 million. The Company also redeemed its 11.40% Series A Preferred Stock in March 1999, which resulted in the avoidance of approximately $15.9 million in annual cash dividends that would have been payable until mandatory redemption in 2008. Common stock equity as a percentage of capitalization has increased from 19% at June 30, 1996 to 40% at December 31, 2002. In addition, the Company’s bonds are rated investment grade by two major credit rating agencies.

The degree to which the Company is leveraged could have important consequences for the Company’s liquidity, including (i) the Company’s ability to obtain additional financing for working capital, capital expenditures, acquisitions, general corporate or other purposes could be limited in the future and (ii) the Company’s higher than average leverage may place the Company at a competitive disadvantage by limiting its financial flexibility to respond to the demands of the competitive market and make it more vulnerable to adverse economic or business changes.

On August 1, 2002, the Company issued two series of pollution control bonds in the amounts of $37.1 million and $33.3 million to replace two series of bonds of equal value. The new bonds are due May 1, 2037 and June 1, 2032, and were issued with a fixed interest rate of 6.25% and 6.375%, respectively. These interest rates are fixed until August 1, 2005, which is the date the bonds are due to be remarketed.

The Company’s Board of Directors previously approved three stock repurchase programs allowing the Company to purchase up to fifteen million of its outstanding shares of common stock. As of March 7, 2003, the Company had repurchased 13,163,129 shares of common stock under these programs for approximately $149.4 million, including commissions. The Company may continue making purchases of its stock at open market prices and may engage in private transactions, where appropriate. Any repurchased shares will be available for issuance under employee benefit and stock option plans, or may be retired.

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Historical Results of Operations

Net income decreased $34.7 million, or $0.66 diluted earnings per share, in 2002 compared to 2001 primarily due to (i) decreased economy sales margins related to significantly reduced wholesale prices in the western United States; (ii) the FERC settlements; (iii) decreased wholesale sales; (iv) increased expense at Palo Verde; (v) increased regulatory expense; (vi) decreased investment performance and (vii) a reduction in the estimate of a contingent tax liability in 2001 with no comparable amount in 2002. This decrease was partially offset by (i) the recovery of energy expenses in New Mexico; (ii) increased retail sales and (iii) decreased interest expense on long-term debt.

Net income increased $5.3 million, or $0.17 diluted earnings per share in 2001 compared to 2000 primarily due to (i) increased economy sales margins; (ii) increased retail sales; (iii) decreased interest on long-term debt and (iv) a reduction in the estimate of a contingent tax liability in 2001 with no comparable amount in 2000. This increase was partially offset by energy expenses not recovered in the New Mexico service area prior to July 2001 and increased maintenance expense due to scheduled outages.

Electric utility operating revenues net of energy expenses decreased $28.2 million in 2002 compared to 2001 primarily due to (i) decreased economy sales margins related to the significantly reduced wholesale prices in the western United States; (ii) decreased wholesale sales and (iii) decreased wheeling revenues. This decrease was partially offset by the recovery of energy expenses in New Mexico and increased retail sales.

Electric utility operating revenues net of energy expenses increased $7.8 million in 2001 compared to 2000 primarily due to increased economy sales margins and increased retail kWh sales. This increase was partially offset by energy expenses not recovered in the New Mexico service area prior to July 2001 and a sales tax refund in 2000 with no comparable activity in 2001.

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Comparisons of kWh sales and electric utility operating revenues are shown below (in thousands):