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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, 2003

OR

For the transition period from                      to                     

Commission file number 0-296

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 30, 2003, the aggregate market value of the voting stock held by non-affiliates of the registrant was $586,138,226 (based on the closing price as quoted on the New York Stock Exchange on that date).

As of March 5, 2004, there were 47,588,360 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 2004 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:

(i)

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TABLE OF CONTENTS

(ii)

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PART I

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 Texas and periodically 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, 2003, the Company’s energy sources consisted of approximately 50% nuclear fuel, 27% natural gas, 9% coal, 14% purchased power and less than 1% generated by wind turbines.

The Company serves approximately 324,000 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 58% and 9%, respectively, of the Company’s operating revenues for the year ended December 31, 2003). In addition, the Company’s wholesale sales include sales for resale to other electric utilities and periodically sales to the CFE and power marketers. 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 5, 2004, the Company had approximately 1,000 employees, 31% of whom are covered by a collective bargaining agreement. A new collective bargaining agreement, which expires June 2006, was entered into with these employees in July 2003. The Company has also begun collective bargaining negotiations with an additional 75 employees from the Company’s meter reading and collections area and facilities services area who voted for union representation in 2003.

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

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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.

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, through the term of their respective operating licenses. The Company’s decommissioning costs are estimated every three years based upon engineering cost studies 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 January 2003, the Company made an additional deposit of $4.7 million into the decommissioning trust fund such that the trust fund met ANPP minimum accumulation levels at December 31, 2002. The Company remained above its minimum funding level as of December 31, 2003. The Company will continue to monitor the status of its decommissioning funds and adjust its deposits, if necessary, to remain at or above its minimum accumulation requirements in the future.

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 estimated 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 estimated 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 compound 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 the Unit 2 steam generator storage. The decommissioning study is stated in 2001 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 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.

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Historically, regulated utilities such as the Company have been permitted to collect in rates the costs of nuclear decommissioning. Under the Texas Restructuring Law, which, among other things, deregulates generation services, the Company, through an affiliated transmission and distribution utility, will be able to collect from customers the costs of decommissioning. The collection mechanism utilized in Texas is a “non-bypassable wires charge” through which all customers, even those who choose to purchase energy from a supplier other than the Company’s retail affiliate, will be required to pay a fee, which includes the cost of nuclear decommissioning, to the Company’s affiliated transmission and distribution utility. In the Company’s case, collection of the fee through the Company’s transmission and distribution utility will begin in Texas if and when retail competition is implemented in the Company’s Texas service territory. See “Regulation – Texas Regulatory Matters – Deregulation” for further discussion.

Spent Fuel Storage. The original spent fuel storage facilities at Palo Verde had sufficient capacity to store all fuel discharged from normal operation of all three Palo Verde units through 2003. Alternative on-site storage facilities and casks have been constructed to supplement the original facilities. In March 2003, APS began removing spent fuel from the original facilities as necessary, and placing it in special storage casks which are stored at the new facilities until it is accepted by the DOE for permanent disposal. The 2003 decommissioning study assumes that costs to store fuel on-site will become the responsibility of the DOE after 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. In December 2003, APS, in conjunction with other nuclear plant operators, filed suit against the DOE on behalf of the Palo Verde Participants to recover monetary damages associated with the delay in the 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

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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 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. New steam generators were installed at Unit 2 during 2003 at an estimated total cost to the Company of $47.1 million. This replacement 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.

APS has identified accelerated degradation in the steam generator 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 $202.1 million (the Company’s portion being $31.9 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, the installation of the Units 1 and 3 replacement steam generators and the completion of power uprates at those units will require the expenditure of $278.6 million (the Company’s portion being $44.0 million). Present plans are for replacement steam generators to be installed at Units 1 and 3 in 2005 and 2007, respectively.

The eventual total cash expenditures for steam generator replacement for Units 1, 2 and 3 is currently estimated to be $718.9 million excluding replacement power costs (the Company’s portion being $113.6 million). As of December 31, 2003, the Company has paid approximately $46.7 million of such costs. The remaining balance is expected to be paid over the course of the steam generator replacements. 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 its wholesale power rates and its competitive retail rates will be sufficient to recover its costs when or if retail competition for generation services begins. 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 of 1954 to provide a system of financial protection for persons who may be injured or persons who may be liable for a nuclear incident. The Price-Anderson Act expired on December 31, 2003. 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 reauthorize the Price-Anderson Act. The Price-Anderson Amendments Act of 2003 has been placed on the legislative calendar under general order (Calendar No. 422). If passed the Act will amend the Atomic Energy Act to: (i) increase from $63 million to $94 million the maximum amount of standard

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deferred premiums charged a licensee following any nuclear incident under an industry retrospective rating plan; and (ii) increase from $10 million to $15 million (adjusted for inflation) in any one year the maximum amount of such premiums for each facility for which the licensee must maintain the maximum amount of primary financial protection. The amount of DOE indemnification currently available under the act is $9.4 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. 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. Presently, 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 $2.8 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. Each of the two coal-fired generating units has 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.

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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 leased the combustion turbine until December 2003 at which time the facilities were purchased at a total purchase price of $8.4 million, which included the balance of any remaining payments under the lease.

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 transmission and distribution network within its New Mexico and Texas retail service area and operates these facilities under franchise agreements with various municipalities. 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 system integrity in the event that any one of these transmission lines is out of service.

Springerville-Diablo Line. The Company wholly 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 wholly 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. The Company owns the Afton 345 kV Substation located approximately 57 miles from the Luna Substation on the Luna-to-Newman portion of the line which interconnects a generator owned and operated by PNM.

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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 purchased and 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 northwest of Phoenix near Peoria, Arizona 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 500 kV switchyards connected to the Palo Verde-Kyrene 500 kV line: the Hassayampa switchyard adjacent to the southern edge of the Palo Verde 500 kV switchyard and the Jojoba switchyard approximately 24 miles from Palo Verde. These switchyards were built to accommodate the addition of new generation and transmission in the Palo Verde area.

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 $0.9 million as of December 31, 2003, which is related to compliance with federal and state environmental standards. 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 aware of any active investigation of its compliance with environmental requirements 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, potentially material 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 fabrication and shipment of Palo Verde Units 1 and 3 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, 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 have been received and analyzed. Based on the analysis of the RFPs received to date, it does not appear as if the selection will require the use of cash by the Company to construct a facility to obtain power for its 2006 requirements. The Company is still evaluating its 2009 requirements.

The Company’s estimated cash construction costs for 2004 through 2007 are approximately $277.0 million. Actual costs may vary from the construction program estimates shown. Such estimates are reviewed and updated periodically to reflect changed conditions.

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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.

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. 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 in place that will furnish 100% of Palo Verde’s operational requirements for uranium concentrates, conversion services and enrichment services through 2008. Such contracts could also provide 100% of enrichment services in 2009 and 2010. The Palo Verde Participants have a contract 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, 2003, approximately $42.2 million had been drawn to finance nuclear fuel. This financing is accomplished through a trust that borrows under the credit 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 consolidated and reported as assets and liabilities of the Company.

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Natural Gas

The Company manages its natural gas requirements through a combination of a long-term supply contract and spot market purchases. The long-term supply contract provides for firm deliveries of gas at market based index prices. In 2003, 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 but which is expected to continue beyond 2005. The Company anticipates it will continue to purchase natural gas at spot market prices on a monthly basis for a portion of the fuel needs for the Rio Grande Power Station for the near term. 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 primarily supplied pursuant to an intrastate natural gas contract that expires in 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. APS, on behalf of the Company and the other Four Corners Participants, has extended the Four Corners coal contract with the supplier to 2016 to coincide with the Four Corners Plant lease with the Navajo Nation. 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.

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 103 MW of firm energy in 2003 and will continue to purchase an identical annual amount through 2005 based on a purchase agreement entered into in 2001. This agreement includes demand, energy and transmission charges. Other purchases of shorter duration were made primarily to replace the Company’s generation resources during planned and unplanned outages.

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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. In Texas, the Company is exempt from the requirements of the Texas Restructuring Law, including utility restructuring and retail competition, until the expiration of the Freeze Period in August 2005. In April 2003, the New Mexico Restructuring Act was repealed and as a result, the Company’s operations in New Mexico will continue to be fully regulated. The Company cannot predict at this time the full effects the repeal of the New Mexico Restructuring Act will have on the Company as it prepares for retail competition in Texas. However, the Company believes that the New Mexico Commission will have to approve the separation of the Company’s operations if and when the Company implements utility restructuring and retail competition for compliance with the Texas Restructuring Law.

Federal Regulatory Matters

Federal Energy Regulatory Commission. 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 into the Company’s wholesale power trading in the western United States during 2000 and 2001 to determine whether the Company engaged in misconduct and, if so, to determine potential remedies. The Company reached settlements with the FERC and other parties in 2002 and 2003. 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. In July 2003, the FERC approved the settlements and on August 5, 2003, the Company deposited the $15.5 million into an interest bearing escrow account to consummate the settlements. The Company believes the FERC’s order resolved all issues between the FERC and the other parties to this investigation. Under the settlements, the Company has agreed to make wholesale sales pursuant to its cost of service rate authority rather than its market-based rate authority for the period December 1, 2002 through December 31, 2004. This agreement allows the Company to sell power into wholesale markets at its incremental cost plus $21.11 per MWh. To the extent that wholesale market prices exceed these agreed upon amounts, the Company will forego the opportunity to realize these additional revenues. Although this provision has not had a significant impact on the Company’s revenues through December 31, 2003, the Company is unable to predict the effect, if any, this will have on the Company’s 2004 revenues.

RTOs. FERC’s rule (“Order 2000”) on Regional Transmission Organizations (“RTOs”) strongly encourages, but does not require, public utilities to form and join RTOs. The Company is an active participant in the development of WestConnect, formerly known as the Desert Southwest Transmission and Reliability Operator. As a participating transmission owner, the Company will ultimately transfer operational authority of its transmission system to WestConnect subject to receiving any necessary regulatory approvals. On October 10, 2002, FERC issued an order indicating that the Company’s 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 a seamless market structure. The Company, however, is anticipated to be

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no more than a 9% participant in WestConnect and cannot control the terms or timing of its establishment. WestConnect will not be operational before the end of the Freeze Period. The establishment of an RTO in the Company’s service area is an important factor in the Company’s ability to establish a Qualified Power Region as defined in the Texas Restructuring Law and the timing of the operations of WestConnect could affect when and whether the Company’s Texas service territory participates in the Texas deregulated market.

Department of Energy. The DOE regulates the Company’s exports of power to the 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 by municipalities and 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 within municipalities in Texas and original jurisdiction over certain other activities of the Company. The decisions of the Texas Commission are subject to judicial review.

Deregulation. The Texas Restructuring Law required certain investor-owned electric utilities to separate power generation activities from transmission and distribution activities by January 1, 2002, and on that date, retail competition for generation services was instituted in some parts of Texas. The Texas Restructuring Law, however, 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. The Texas Commission recently opened a project (Project No. 28971) to evaluate the readiness of the Company’s service area in Texas for retail competition for generation services. In this project, the Texas Commission may specify in advance the factors that are important in deciding when and whether to open the Company’s service area in Texas to customer choice. One of the key factors that will likely be utilized by the Texas Commission in its determination is the progress that has been made in developing an RTO in the Company’s service area. Public hearings to discuss the readiness of the Company’s service area were held on March 4, 2004 in El Paso and will be held in Austin in April 2004. There is substantial uncertainty about both the regulatory framework and market conditions that will exist if and when retail competition is implemented in the Company’s service territory and the Company may incur substantial preparatory, restructuring and other costs that may not ultimately be recoverable. There can be no assurance that

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deregulation will not adversely affect the future operations, cash flows and financial condition of the Company.

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 providing electricity and seek recovery of past undercollections of fuel revenues, subject to periodic final review by the Texas Commission in fuel reconciliation proceedings.

On March 10, 2004, the Texas Commission announced its decision in PUC Docket No. 26194, a case in which the Company sought to reconcile its Texas jurisdictional fuel costs for the period January 1, 1999 through December 31, 2001. At issue was the Company’s request to recover an additional $15.8 million, before interest, from its Texas customers as a surcharge because of fuel undercollections from January 1999 through December 2001. The Texas Commission disallowed approximately $4.5 million of Texas jurisdictional expenses, before interest, consisting primarily of (i) approximately $4.2 million of purchased power expenses which the Texas Commission characterized as “imputed capacity charges,” and (ii) approximately $0.3 million in fees which were deemed to be administrative costs, not recoverable as fuel. In Texas, capacity charges are not eligible for recovery as fuel expenses, but are to be recovered through the Company’s base rates. As the Company’s base rates were frozen during the time period in question, the $4.2 million of “imputed capacity charges” would be permanently disallowed, and hence not recoverable from its Texas customers.

The Texas Commission’s decision modifies the Proposal for Decision issued September 19, 2003 by the Administrative Law Judges (“ALJs”). The ALJs had recommended that approximately $21.2 million of the Company’s purchased power expense should be disallowed as imputed capacity charges and not recovered from Texas jurisdictional customers.

The Company has incurred similar purchased power costs for the fuel reconciliation period beginning January 1, 2002. The Company believes that it has accounted for its purchased power costs during the reconciliation period beginning January 2002 in a manner consistent with the Texas Commission’s decision in PUC Docket No. 26194. However, the Texas Commission has indicated its desire to conduct a generic rulemaking proceeding to determine a statewide policy for the appropriate pricing of capacity in purchased power contracts. There can be no assurance, however, as to the outcome of such rulemaking and the potential impact on the Company with respect to fuel recovery in future reconciliation periods if the Texas Commission adopts a different methodology in a subsequent rulemaking proceeding.

The Texas Commission’s decision is subject to appeal by the various parties and the Company is unable to predict the ultimate outcome of any appeals that may be filed in this case.

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

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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 2003, 2002 and 2001 to be approximately $0.8 million, $1.3 million and $1.1 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 or comparable evidence of collectibility is obtained. Performance penalties are recorded when assessed as probable by the Company.

Texas Renewable Energy Requirement. Chapter 39 of the Public Utility Regulatory Act (“PURA”), implemented by Senate Bill 7 in the 1999 legislative session, requires that, by January 1, 2009, an additional 2,000 MW of generating capacity from renewable energy technologies be installed in the state. The renewable energy requirement is to be added in increments with the cumulative installed renewable capacity in Texas totaling 1,703 MW by January 1, 2005, 2,280 MW by January 1, 2007, and 2,880 MW by January 1, 2009. The requirements of this goal are placed on retail electric providers (“REPs”), who provide competitive retail electric service in the state of Texas. Utilities that have not implemented retail competition may have renewable energy requirements based on orders of the Texas Commission.

Until the end of the Freeze Period, the Company is exempt from PURA Chapter 39 and Texas Commission rules implementing the renewable requirements. However, once the Freeze Period ends, any renewable energy requirement applicable to the Company could be based on the percentage of the competitive retail load that will be served by the Company (or the Company’s REP) in relation to the total competitive retail load served in Texas. It is not clear when the Company will need to meet a renewable energy requirement in Texas or what the obligation will be. The Company is currently reviewing the outcome of its New Mexico RFPs, for renewable energy to assess possible scenarios for meeting possible future Texas requirements, which includes the purchase of renewable power and/or credits.

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 April 2003, the New Mexico Restructuring Act was repealed and as a result the Company’s operations in New Mexico will continue to be fully regulated. The Company cannot predict at this time the full effects the repeal of the New Mexico Restructuring Act will have on the Company as it prepares for retail competition in Texas.

Fuel. In June 2001, the New Mexico Commission approved a fuel and purchased power cost adjustment clause. On May 31, 2003, the Company submitted a rate compliance filing whereby the Company proposed to continue a base rate recovery of $0.01949 per kWh and continue the fuel and

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purchased power cost adjustment to recover the remainder of fuel and purchased power costs. The Company and all intervenors entered into the New Mexico Stipulation on the Company’s compliance filing.

New Mexico Rate Stipulation. On January 21, 2004, the Company and all intervenors to the rate compliance filing entered into and filed the New Mexico Stipulation whereby, among other things, the Company agreed for a period of three years beginning June 1, 2004 to (i) freeze base rates after an initial non-fuel base rate reduction of 1%; (ii) fix fuel and purchased power cost associated with 10% of the Company’s jurisdictional retail sales in New Mexico at $0.021 per kWh; (iii) leave subject to reconciliation the remaining 90% of the Company’s New Mexico jurisdictional fuel and purchased power costs; (iv) continue the collection of a portion of fuel and purchased power costs in base rates as presently collected in the amount of $0.01949 per kWh; (v) price power provided from Palo Verde Unit 3 to the extent of its availability at an 80% nuclear, 20% gas fuel mix (currently such power is priced at 75% nuclear, 25% gas fuel mix) and (vi) deem reconciled, for the period June 15, 2001 through May 31, 2004, the Company’s fuel and purchased power costs for the New Mexico jurisdiction. The New Mexico Stipulation is subject to the New Mexico Commission’s approval. The New Mexico Commission hearing on the New Mexico Stipulation was held on February 25, 2004. The Company anticipates a ruling on the New Mexico Stipulation prior to June 2004 with the new rates implemented on or about June 1, 2004. The Company cannot predict the outcome of these proceedings or how the New Mexico Commission will rule.

New Mexico Renewable Energy Requirement. The New Mexico Commission has adopted renewable energy portfolio requirements and has mandated that 5% of all New Mexico retail jurisdictional energy sales in 2006 be supplied by renewable resources or certificates. The renewable portfolio standard increases by 1% each year until 2011, and is set at 10% in 2011 and thereafter. In February 2004, the Company issued a RFP for renewable energy from certified renewable sources to meet the renewable energy portfolio requirements. Based on responses to the RFP, the Company will develop a plan to meet the New Mexico Commission’s renewable energy requirements. In the 2004 New Mexico legislative session, the Renewable Energy Act was enacted which directs the New Mexico Commission to adopt a rule consistent with the law, and requires rate recovery for the reasonable costs of compliance with the renewable requirements.

Sales for Resale

The Company provides up to 10 MW of firm capacity, associated energy, and transmission service to the Rio Grande Electric Cooperative pursuant to an ongoing contract which requires a two-year notice to terminate. No such notice has been received. The Company also made sales of interruptible energy to CFE during the months of June and July 2003 of 13,711 MWh and 4,525 MWh, respectively.

Power Sales Contracts

As of March 5, 2004, the Company had entered into one significant agreement with a counterparty for forward off-peak firm sales of electricity of 50 MW for 2004.

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The Company also has an agreement with a counterparty for power exchanges under which the Company received 30 MW of on-peak capacity and associated energy during 2003 at the Eddy County tie and concurrently delivered the same amount at Palo Verde and/or Four Corners. The on-peak exchange amount remains at 30 MW 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 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.”

Franchises and Significant Customers

City of El Paso Franchise

The Company’s major franchise is with the City of El Paso, Texas (“City”). The franchise agreement includes a 2% annual franchise fee (approximately $7.7 million per year currently) and provides an arrangement for the Company’s utilization of public rights-of-way necessary to serve its retail customers within the City. The franchise with the City extends through August 1, 2005.

In a provision of the franchise agreement, the City has an option to acquire all of the non-cash assets of the Company at the end of the term of the franchise on August 1, 2005, at a purchase price equal to the fair market value of the assets (measured on a cost of reproduction basis) on the date one year prior to the end of the term. The purchase price is then subject to certain adjustments to roll the value of the assets forward to the end of the term. If the City wishes to exercise its option, it must deliver written notice to the Company one year prior to the expiration of the franchise term.

Las Cruces Franchise

In February 2000, the Company and Las Cruces entered into a seven-year franchise agreement with a 2% annual franchise fee (approximately $1.1 million per year currently) for the provision of electric distribution service. Las Cruces is prohibited during this seven-year period from taking any action to condemn or otherwise attempt to acquire the Company’s distribution system, or attempt to operate or build its own electric distribution system. Las Cruces will have a 90-day non-assignable option at the end of the Company’s seven-year franchise agreement to purchase the portion of the Company’s distribution system that serves Las Cruces at a purchase price of 130% of the Company’s book value at that time. If Las Cruces exercises this option, it is prohibited from reselling the distribution assets for two years. If Las Cruces fails to exercise this option, the franchise and standstill agreements will be extended for an additional two years.

Military Installations

The Company currently serves Holloman Air Force Base (“Holloman”), White Sands Missile Range (“White Sands”) and the United States Army Air Defense Center at Fort Bliss (“Ft. Bliss”). The Company’s sales to the military bases represent approximately 3% of annual operating revenues. The Company currently has long-term contracts with all three military bases that it serves. The Company signed a contract with Ft. Bliss in December 1998 under which Ft. Bliss will take service from the Company through December 2008. The Company has a contract to provide retail electric service to Holloman for a ten-year term which began in December 1995. In May 1999, the Army and the Company entered into a new ten-year contract to provide retail electric service to White Sands.

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

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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. Substantially all of the Company’s utility plant is subject to liens to secure the First Mortgage Bonds.

In addition, the Company leases executive and administrative offices in El Paso, Texas under a lease which expires in May 2007.

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, except as described below, 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. The suit seeks undisclosed compensatory damages for the class as well as costs and attorneys’ fees. The lead plaintiff, Carpenters Pension Fund of Illinois, filed a consolidated amended complaint on July 2, 2003, alleging, among other things, that the Company and certain of its current and former directors and officers violated securities laws by failing to disclose that some of the Company’s revenues and income were derived from an allegedly unlawful relationship with Enron. The allegations arise out of the FERC investigation of the power markets in the western United States during 2000 and 2001, which the Company previously settled with the FERC Trial Staff and certain intervening parties. See Part I, Item 1, “Regulation – Federal Regulatory Matters.” On August 15, 2003, the Company and the individual defendants filed a motion to dismiss the complaint for failure to state a claim upon which relief can be granted. On November 26, 2003, the Court denied the motion to dismiss as to the Company and three of the individual defendants and granted the motion to dismiss as to two individual defendants. The lead plaintiff filed its motion for class certification on January 9, 2004, seeking to certify a class consisting of all persons who purchased or otherwise acquired Company securities between February 14, 2000 and October 21, 2002. This matter is presently set for trial on March 28, 2005. While the Company believes the lawsuit is without merit and intends to defend itself vigorously, the Company is unable to predict the outcome.

On February 10, 2003, the Company received a letter written by a Pennsylvania law firm on behalf of the holder of approximately 200 shares of common stock of the Company (the “shareholder”), that demands 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 participate in improper transactions with Enron Corporation and certain of its

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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 and certain intervenors. In accordance with Texas law, the independent and disinterested directors of the Company conducted an independent inquiry and concluded that a lawsuit against the Board is not in the best interests of the Company. To date, the shareholder has not filed a shareholder derivative lawsuit against the members of the Board. The Company is unable to predict the outcome of this matter.

On May 21, 2003, the Company was served with a complaint by the Port of Seattle seeking civil damages under the Sherman Act, the Racketeer Influenced and Corrupt Organization Act, and state anti-trust laws, as well as for breach of contract and fraud (Port of Seattle v. Avista Corporation, et al., No. CV03-117OP). The complaint was filed in the United States District Court for the Western District of Washington. The complaint alleges that the Company, indirectly through its dealings with Enron, conspired with the other named defendants to manipulate the California energy market, which had the effect of artificially inflating the price that the Port of Seattle paid for electricity. On December 4, 2003, the case was transferred to the United States District Court for the Southern District of California for inclusion in the California Wholesale Electricity Antitrust Multi-District Litigation cases pending in that district (re-styled Port of Seattle v. Avista Corporation, et al., No. CV 03-2474-RHW, MDL No. 1403). The Company, together with several other defendants, filed a motion to dismiss on July 29, 2003. The motions to dismiss are scheduled for oral argument on March 26, 2004. While the Company believes the lawsuit is without merit and will defend itself vigorously, it is unable to predict the outcome of this case.

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. The Company has reached a tentative agreement, subject to IRS final approval, to settle these and all other issues relative to its 1996 through 1998 federal income tax returns. The Company expects the IRS will make a final decision regarding the proposed settlement by mid 2004. Should the proposed settlement be rejected by the IRS, the Company cannot predict the eventual outcome of this matter. However, 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, 2003 is a reasonable estimate of any additional tax that may be due.

On February 9, 2004, Enron North America Corp. (“ENA”) filed suit against the Company seeking payment of approximately $5.4 million, plus interest and costs, relating to certain natural gas supply contracts (Enron North America Corp. v. El Paso Electric Co., Case No. 01-16034, United States Bankruptcy Court, Southern District of New York). The complaint alleges that ENA entered into two natural gas supply contracts with the Company which automatically terminated as a result of ENA’s bankruptcy. ENA contends that, under the terms of the contracts, the Company owes ENA termination payments because the market price of natural gas at the date of termination was lower than the contract price. While ENA acknowledges that the contracts contain a provision (the “One-Way Payment Provision”) under which the termination payment would be calculated to be zero, ENA seeks a ruling

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from the court that the One-Way Payment Provision is unenforceable and that the Company should be required to pay termination payments in the amount of approximately $5.4 million, plus interest and costs. The first of these two contracts covers gas to be supplied by ENA during the months of November and December of 2001 (the “2001 Contract”). The Company estimates that the value of the termination payment claimed by ENA under the 2001 Contract is approximately $1.8 million. The second of these two contracts covers gas to be supplied by ENA during the months of January through December of 2002 (the “2002 Contract”). The Company estimates that the value of the termination payment claimed by ENA under the 2002 Contract is approximately $3.6 million. Based upon the Company’s assessment of the probability of an adverse outcome, the Company has expensed a pre-tax amount of $1.5 million as of December 31, 2003 for this matter. The Company intends to defend itself vigorously, but cannot predict the outcome of this matter.

On October 2 and 3, 2003, employees in the Company’s meter reading and collections areas, comprised of 68 employees, voted in favor of representation by the International Brotherhood of Electrical Workers, Local 960 (“Local 960”). This vote was certified by the National Labor Relations Board (“NLRB”) on October 14, 2003. In addition, employees in the Company’s facilities services area, comprised of seven employees, voted in favor of representation by Local 960 on October 16, 2003. This vote was certified by the NLRB on October 24, 2003. The Company has begun collective bargaining negotiations with Local 960 on behalf of these employees.

On November 3, 2003, TNP filed a complaint against the Company with the FERC, asking the FERC to make a determination that TNP has a rollover right to network-type transmission service over the Company’s transmission system. TNP asserts that it has such rights under the rollover provisions of FERC Order No. 888 relating to its power sale agreement with the Company that expired on December 31, 2002. The Company’s position is that the transmission service provided by the Company to TNP under the expired power sale agreement was point-to-point service and not network service and that the Company does not have the capacity to provide the network service that TNP seeks. Due to existing transmission constraints, a FERC ruling granting TNP’s request could adversely impact the Company’s ability to import lower cost power from Palo Verde and Four Corners to serve its base load to the extent of the transmission rights granted to TNP. A hearing on this matter before an administrative law judge is scheduled for June 15, 2004. The Company cannot predict the likely outcome of this matter or the full effect that an adverse ruling would have on the Company.

Not applicable.

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PART II

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 5, 2004, there were 4,646 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, bond ratings, and earnings per share.

During 2003, the Company repurchased 2.1 million shares of common stock for $24.2 million to complete its previously approved stock repurchase programs. Since the inception of the stock repurchase programs in 1996, the Company repurchased 15 million shares in total at an aggregate cost of $171.0 million, including commissions. In February 2004, the Board of Directors authorized a new stock repurchase program permitting the repurchase of up to 2 million shares of its outstanding common stock. The Company may make purchases of its stock at open market prices and may engage in private transactions, where appropriate. The repurchased shares will be available for issuance under employee benefit and stock option plans, or may be retired.

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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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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 determinations by regulators that may adversely affect the Company’s ability to recover incurred fuel costs in rates; (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 for Palo Verde Units 1 and 3 and other costs at Palo Verde; (v) the costs of legal defense and possible judgments which may accrue as the result of litigation arising out of the FERC investigation or any other regulatory proceeding; (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 utilized by the Company. 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 in future periods 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:

Collection of Fuel Expense

In general, through regulation, the Company’s fuel and purchased power expenses are passed through to its regulated customers. These costs are subject to reconciliation by the Texas and New Mexico Commissions. Prior to the completion of a reconciliation, the Company records fuel expenses as incurred. In the event that a disallowance occurs during a reconciliation proceeding, the

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amounts recorded for fuel and purchased power expenses could differ from the amounts allowed to be collected by the Company from its customers and the Company could incur a loss to the extent of the disallowance.

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 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, 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 writedown 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 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 determines how it will fund its share of those estimated costs by making assumptions about future investment returns and future cost escalations. The funds are invested in professionally managed investment trust accounts. The Company is required to establish a minimum accumulation and a minimum funding level in its decommissioning trust accounts at the end of each annual reporting period in accordance with the ANPP Participation Agreement. 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, assuming that Palo Verde Units 1, 2 and 3 operate over their remaining lives (which includes an assessment of the probability of a license extension) and that the DOE assumes responsibility for permanent disposal of spent fuel at plant shut down. 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

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decommissioning. Under deregulation legislation in Texas, the Company expects to continue to be able to collect from customers the costs of decommissioning.

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. The Company has reached a tentative agreement, subject to IRS final approval, to settle these and all other issues relative to its 1996 through 1998 federal income tax returns. The Company expects the IRS will make a final decision regarding the proposed settlement by mid 2004. Should the proposed settlement be rejected by the IRS, the Company cannot predict the eventual outcome of this matter. However, 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, 2003 is a reasonable estimate of any additional tax that may be due.

Overview

El Paso Electric Company is an investor owned electric utility that serves retail customers in west Texas and southern New Mexico and wholesale customers in Texas and periodically 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, wind powered resources and purchased power. The Company owns or has significant ownership interests in four major 345 kV transmission lines and three 500 kV transmission lines utilized to transfer power from Palo Verde and Four Corners, and owns the transmission and 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 and the Company’s debt service obligations.

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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 would remain regulated, from its power generation and energy services businesses, which would operate in a competitive market in the future. New Mexico repealed the New Mexico Restructuring Act in April 2003, and the Company’s operations in New Mexico will remain fully regulated. In Texas, the Company’s service territory has not yet been deregulated, but the Company is preparing for retail competition. If the Company does not enter retail competition for generating services at the end of the Freeze Period, the Company’s generating services will continue to be regulated by the Texas Commission. There is substantial uncertainty about both the regulatory framework and market conditions that will exist if and when retail competition is implemented in the Company’s service territory 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 potential for 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, alternate sources of economical power, including co-generation of electric power. In fact, 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, the Company may not be able to replace such revenues through either the addition of new customers, an increase in rates to remaining customers, or sales in the economy market.

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 in Palo Verde Units 1 and 3; (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. As a result, the Company cannot raise its base rates in Texas in the event of increases in non-fuel costs or loss of revenue. 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.

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Liquidity and Capital Resources

The Company’s principal liquidity requirements in the near-term are expected to consist of interest payments on the Company’s indebtedness, operating and capital expenditures related to the Company’s generating facilities and transmission and distribution systems, income and other taxes, and reorganization costs related to deregulation in Texas, if and when deregulation occurs. The Company expects that cash flows from operations will be sufficient for such purposes.

The Company’s contractual obligations as of December 31, 2003 are as follows (in thousands):

Pollution control bonds of $193.1 million are subject to remarketing in 2005, and first mortgage bonds of $182.2 million are scheduled to mature in 2006. The Company expects that these obligations and the $100 million revolving credit facility, which matures in January 2005 (against which approximately $42.2 million had been drawn for nuclear fuel purchases as of December 31, 2003) will be refinanced through the capital and credit markets. Additionally, the Company has $207.2 million of first mortgage bonds which become callable in 2006. The Company’s ability to access capital and credit markets may be adversely affected by uncertainties related to operating in a competitive energy market, tight credit markets and debt rating agency actions.

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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 steam generators in Palo Verde Units 1 and 3. See Part I, Item 1, “Business – Construction Program.”

During 2003, 2002 and 2001, the Company generated $0.7 million and utilized $96.6 million and $128.0 million, respectively, of regular federal tax loss carryforwards. The Company anticipates that existing regular federal tax loss carryforwards will be fully utilized by mid-2004, should the IRS settlement for the tax years 1996 through 1998 be approved by the IRS, and that the Company’s cash flow requirements for income taxes in 2004 will increase compared to the requirement for 2003.

The Company anticipates its cash flow requirements associated with its retirement plans and other postretirement benefit plans and its cash flow requirements related to contributions to the decommissioning trust funds will decrease as compared to the related cash flow requirements in 2003. The Company contributed an additional $4.7 million to the decommissioning trust funds in January 2003 and an additional $3.2 million to one of its retirement plans in September 2003 in order to meet its funding requirements as of December 31, 2002. The Company is continually evaluating its funding requirements related to its retirement plans, other postretirement benefit plans, and decommissioning trust funds.

As of December 31, 2003, the Company had approximately $34.4 million in cash and cash equivalents, a decrease of $40.7 million from the balance of $75.1 million on December 31, 2002. This decrease was primarily the result of the retirement in February 2003 of the Company’s Series C First Mortgage Bonds. Any amounts not borrowed under the Company’s $100 million revolving credit facility for nuclear fuel purchases may be used by the Company for working capital needs. As of December 31, 2003, approximately $42.2 million had been drawn for nuclear fuel purchases. No amounts are currently outstanding on this facility for working capital needs.

The Company has significant debt service obligations. Since inception of its deleveraging program in 1996, the Company has repurchased or retired with internally generated cash $556.5 million of first mortgage bonds, including the repayment of approximately $36.1 million of Series C First Mortgage Bonds at their maturity and the repurchase of approximately $3.3 million of first mortgage bonds during the first quarter of 2003. First Mortgage Bonds totaling $6.0 million were repurchased in early 2004. Common stock equity as a percentage of capitalization, including current portion of long-term debt and financing obligations, was 44% as of December 31, 2003.

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

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During 2003, the Company repurchased 2.1 million shares of common stock for $24.2 million to complete its previously approved stock repurchase programs. Since the inception of the stock repurchase programs in 1996, the Company repurchased 15 million shares in total at an aggregate cost of $171.0 million, including commissions. In February 2004, the Board of Directors authorized a new stock repurchase program permitting the repurchase of up to 2 million shares of its outstanding common stock. The Company may make purchases of its stock at open market prices and may engage in private transactions, where appropriate. The repurchased shares will be available for issuance under employee benefit and stock option plans, or may be retired.

Historical Results of Operations

Beginning on January 1, 2003, the Company adopted SFAS No. 143, “Accounting for Asset Retirement Obligations,” which substantially changed the reporting of the Company’s decommissioning obligation at Palo Verde and Four Corners. During 2003, the Company recognized the effect of this accounting change, which increased net income by $39.6 million, net of tax. The above table compares historical results to pro forma results which assume SFAS No. 143 had been applied in both 2002 and 2001. Income before the cumulative effect of accounting change decreased $13.0 million, or $0.25 diluted earnings per share in 2003 compared to the pro forma results for 2002. This after-tax decrease resulted primarily from (i) decreased wholesale sales revenue of $15.6 million primarily related to the expiration of two long-term contracts; (ii) the impairment loss on the CIS project of $10.7 million; (iii) increased pension and benefits expenses of $3.1 million; (iv) Texas fuel disallowance of $2.8 million; (v) increased insurance expenses of $2.8 million; (vi) increased outside services of $2.2 million; and (vii) increased expense at Palo Verde of $1.3 million. These decreases were partially offset by (i) the 2002 accrual for the FERC settlements of $9.5 million with no comparable amount in 2003; (ii) increased sales and margins on economy sales of $6.3 million; (iii) increased retail sales of $5.6 million; (iv) decreased interest on long-term debt of $2.3 million; (v) decreased loss on extinguishment of debt of $2.1 million; and (vi) decreased MiraSol operating loss of $1.9 million.

Pro forma income before cumulative effect of accounting change decreased $34.5 million or $0.65 diluted earnings per share in 2002 compared to the pro forma results for 2001. This after-tax decrease was primarily due to (i) decreased economy sales margins of $20.3 million related to significantly reduced wholesale prices in the western United States; (ii) the FERC settlements of $9.5 million; (iii) increased demand charges of $4.5 million; (iv) decreased wholesale sales of $3.7 million; (v) increased expense at Palo Verde of $2.8 million; (vi) increased regulatory expense of $2.4 million; (vii) decreased investment performance of $2.1 million; and (viii) a reduction in the estimate of a contingent tax liability in 2001 of $2.5 million with no comparable amount in 2002. These

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decreases were partially offset by (i) the recovery of energy expenses in New Mexico of $6.3 million; (ii) increased retail sales of $5.4 million; and (iii) decreased interest expense on long-term debt of $4.7 million.

Operating revenues net of energy expenses decreased $16.4 million in 2003 compared to 2002 primarily due to (i) decreased wholesale sales of $25.5 million; (ii) Texas fuel disallowance of $4.5 million; and (iii) a $4.0 million decrease in revenue from the energy service operations partially offset by increased sales and margins on economy sales of $10.3 million and increased retail sales of $9.2 million.

Operating revenues net of energy expenses decreased $38.8 million in 2002 compared to 2001 primarily due to (i) decreased economy sales margins of $33.2 million related to the significantly reduced wholesale prices in the western United States; (ii) decreased revenue from the energy services operations of $10.6 million; (iii) increased demand charges of $7.3 million; and (iv) decreased wholesale sales of $6.0 million. This decrease was partially offset by the recovery of energy expenses in New Mexico in 2002 of $10.3 million, with no comparable recovery in 2001 and increased retail sales of $8.8 million.

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

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