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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, 2004

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, 2004, the aggregate market value of the voting stock held by non-affiliates of the registrant was $725,531,699 (based on the closing price as quoted on the New York Stock Exchange on that date).

As of February 28, 2005, there were 47,496,148 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 2005 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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FORWARD-LOOKING STATEMENTS

Certain matters discussed in this Annual Report on Form 10-K other than statements of historical information are “forward-looking statements.” The Private Securities Litigation Reform Act of 1995 has established that these statements qualify for safe harbors from liability. Forward-looking statements may include words like the Company “believes”, “anticipates”, “targets”, “expects”, “pro forma”, “estimates”, “intends” and words of similar meaning. Forward-looking statements describe the Company’s future plans, objectives, expectations or goals. Such statements address future events and conditions concerning:

These forward-looking statements involve known and unknown risks that may cause the Company’s actual results in future periods to differ materially from those expressed in any forward-looking statement. Factors that would cause or contribute to such differences include, but are not limited to, such things as:

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These lists are not all-inclusive because it is not possible to predict all factors. A discussion of some of these factors is included in this document under the headings “Risk Factors” and “Management’s Discussion and Analysis” “–Summary of Critical Accounting Policies and Estimates” and “–Liquidity and Capital Resources.” This report should be read in its entirety. No one section of this report deals with all aspects of the subject matter. Any forward-looking statement speaks only as of the date such statement was made, and the Company is not obligated to update any forward-looking statement to reflect events or circumstances after the date on which such statement was made except as required by applicable laws or regulations.

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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 a wholesale customer 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, 2004, the Company’s energy sources consisted of approximately 49% nuclear fuel, 27% natural gas, 8% coal, 16% purchased power and less than 1% generated by wind turbines.

The Company serves approximately 332,000 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 59% and 9%, respectively, of the Company’s operating revenues for the year ended December 31, 2004). 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 February 28, 2005, the Company had approximately 1,000 employees, 33% 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. In addition, the Company is presently conducting collective bargaining negotiations with an additional 138 employees from the Company’s meter reading and collections area, facilities services area and customer service area who voted for union representation in 2003 and 2004.

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 (“SEC”). In addition, copies of the annual report will be made available free of charge upon written request. The SEC also maintains an internet site that contains reports, proxy and information statements and other information regarding issuers that file electronically with the SEC. The address of that site is www.sec.gov.

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.

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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.

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. The Company remained above its minimum funding level as of December 31, 2004. 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 needed to 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

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to significant uncertainty. The decommissioning study is updated every three years. The 2004 study is expected to be complete in the second quarter of 2005. 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. The Company, through an affiliated transmission and distribution utility, will be able to continue to collect from customers the costs of decommissioning if and when it becomes subject to the Texas Restructuring Law. 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 2001 decommissioning study assumed 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

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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 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 a total cost to the Company of approximately $45.4 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. The eventual total project cash expenditures for steam generator replacements for Units 1, 2 and 3 are currently estimated to be $724.0 million excluding replacement power costs (the Company’s portion being $114.4 million). As of December 31, 2004, the Company has paid approximately $59.0 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. Despite extensive debate, the 108th Congress adjourned without passing comprehensive energy legislation which would have extended the Price-Anderson Act. While introduction of energy legislation in the 109th Congress is pending, it remains unclear what its course may be. Proposals to separate less controversial provisions such as the reauthorization of the Price-Anderson Act from the comprehensive legislation were resisted by the House and Senate leadership.

Current versions of energy omnibus legislation, if passed, would provide for the reauthorization of the Price-Anderson Act, thus amending the Atomic Energy Act to: (i) increase from $63 million to $95.8 million the maximum amount of standard 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

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facility for which the licensee must maintain the maximum amount of primary financial protection. The aggregate amount of DOE indemnification currently available to all licensees under the Price-Anderson 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 $2.75 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. 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 Company purchased the facilities.

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. The Company owns 66.7% of the terminal. 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. If the United States regulates green house gas emissions, the Company’s fossil fuel generation assets will be faced with the additional cost of monitoring, controlling and reporting these emissions. 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 $1.3 million as of December 31, 2004, 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.

Along with many other companies, the Company received from the Texas Commission on Environmental Quality (“TCEQ”) a request for information dated October 15, 2003 in connection with environmental conditions at a facility in San Angelo, Texas that has been owned and operated by the San Angelo Electric Service Company (“SESCO”). The Company’s written response to TCEQ notes that SESCO performed repair services for certain Company electrical equipment between 1981 and 1991, prior to the Company’s bankruptcy. Although the SESCO site has not been designated as a state or federal Superfund site and the Company has not been named as a “responsible party” or a “potentially responsible party” at that site, the Company received in October 2004 an invitation to participate in site cleanup activities from a group of private companies that are conducting certain cleanup activities at the SESCO site. At this time, the Company has not agreed to participate in the cleanup of the SESCO site

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and is unable to predict the outcome of this matter, although the Company has no reason at present to believe that it will incur material liabilities in connection with the SESCO site.

Except as described herein, the Company is not aware of any other active investigation of its compliance with environmental requirements by the Environmental Protection Agency, the TCEQ or the New Mexico Environment Department which is expected to result in any material liability. Furthermore, except as described herein, the Company is not aware of any unresolved, potentially material liability it would face pursuant to the Comprehensive Environmental Response, Comprehensive Liability Act of 1980, also known as the Superfund law.

Construction Program

Utility construction expenditures reflected in the following table consist primarily of local generation (including cost of capacity to replace units to be retired), expanding and updating the transmission and distribution systems and the cost of capital improvements and replacements at Palo Verde, including the fabrication and installation of Palo Verde Units 1 and 3 steam generators. Replacement power costs expected to be incurred during the replacement of Palo Verde steam generators are not included in construction costs. Studies indicate that the Company will need additional supply-side and demand-side resources to meet increasing load requirements on its system. As a result, the Company is currently evaluating various alternatives to meet its load requirements, but those costs are not included in the table.

The Company’s estimated cash construction costs for 2005 through 2008 are approximately $498 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 2016 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. This facility was renewed in 2004 for a five-year term ending December 17, 2009. At December 31, 2004, approximately $41.2 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. The Company may request a release and return of the collateral provided that the Company maintains certain credit ratings and meets other conditions. 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 2004, 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. This is expected to continue in 2005. Interstate gas is delivered under a base firm transportation contract that expires in July 2005. The Company expects to renew this contract beyond 2005, on terms to be negotiated between the parties. 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 is 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.

In the fourth quarter of 2004, upon preliminary review of a study conducted by an outside engineering firm, the Company increased its estimated final reclamation and coal mine closure liability related to the Company’s interest in Four Corners from $7.4 million to $10.5 million. The $3.1 million increase (in 2004 pre-tax dollars) in its estimated reclamation and coal mine closure liability resulted in a $2.4 million charge to energy expense and a $0.7 million increase in regulatory assets.

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 2004 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. In 2004, the Company entered into a 20-year contract, beginning in 2006, for the purchase of up to 133 MW of capacity and associated energy from SPS. This contract includes a demand charge, energy charge and a transmission charge. 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 has been exempt from the requirements of the Texas Restructuring Law, including utility restructuring and retail competition. The Texas Commission recently adopted a rule that would further delay competition in the Company’s Texas service territory until at least the time that an independent regional transmission organization (“RTO”) begins operation in its relevant power markets. 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 should it be required to ultimately implement 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 and Enron engaged in misconduct and, if so, to determine potential remedies. The Company reached settlements with the FERC and other parties in 2002 and 2003. 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 agreed to refund $15.5 million and 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 allowed the Company to sell power into wholesale markets at its incremental cost plus $21.11 per MWh. To the extent that wholesale market prices exceeded these agreed upon amounts, the Company lost the opportunity to realize these additional revenues. This provision did not have a significant impact on the Company’s revenues through December 31, 2004. The Company’s ability to make wholesale sales pursuant to its market-based rate authority was restored on January 1, 2005.

RTOs. FERC’s rule (“Order 2000”) on 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 no more than a 9% participant in WestConnect and cannot control the terms or timing of its establishment. WestConnect will not be operational for several years. The establishment of an independent RTO in the Company’s service area is a prerequisite for the Company to be considered part of a Qualified Power Region as defined in the

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Texas Restructuring Law. The timing of the operations of WestConnect could affect when and whether the Company’s Texas service territory is deregulated under the Texas Restructuring Law.

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. On October 13, 2004, the Texas Commission approved a rule further delaying retail competition in the Company’s Texas service territory. The rule approved by the Texas Commission sets a schedule which identifies various milestones for the Company to reach before competition can begin. The first milestone calls for the development, approval by the FERC, and commencement of independent operation of a RTO, including the development of retail market protocols to facilitate retail competition. The complete transition to retail competition would occur upon the completion of the last milestone which would be the Texas Commission’s final evaluation of the market’s readiness to offer fair competition and reliable service to all retail customers. The Company believes that adoption of this rule will likely delay retail competition in El Paso for at least several years. 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 would not adversely affect the future operations, cash flows and financial condition of the Company.

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Renewables and Energy Efficiency Programs. Notwithstanding the Commission’s approval of a rule further delaying competition in the Company’s Texas service territory, the Company will become subject to the renewable energy and energy efficiency requirements of the Texas Restructuring Law on January 1, 2006. Under the renewable energy requirements, the Company will have to annually obtain its pro rata share of renewable energy credits as determined by the Texas Commission, based on total Texas retail sales subject to renewable energy credit allocation. The Company’s ultimate obligation to obtain renewable energy credits will not be known until January 31 of the year following the compliance year, and it will have until March 31 to obtain, if necessary, and submit to the Texas Commission, sufficient credits. In addition, by January 1, 2007 and January 1, 2008, the Company will be required to fund incentives for energy efficiency savings that will achieve the goal of meeting 5% and 10% of its growth in demand through energy efficiency savings, respectively. Preparatory costs incurred by the Company to meet these requirements will not be recoverable in the Company’s Texas service territory prior to the expiration of the Freeze Period.

Termination of Freeze Period. The Freeze Period expires on August 1, 2005. Thereafter, the Company will be subject to traditional cost of service regulation by the Texas cities it serves and by the Texas Commission. Its present rates will stay in effect until changed by a city or the Texas Commission. Any such change would be initiated with either a request by the Company or a complaint by a regulator or customer. Any rate change order would be preceded by discovery and presentation of evidence. Any decision by a city would be subject to appellate review by the Texas Commission. The Company has no present intention to request a base rate change, and no complaints against the Company’s base rates are pending.

The end of the Freeze Period may also bring an end to the 50/50 sharing of off-system sales margins between the Company and its customers. The current fuel rule in Texas provides that such margins are to be fully credited to customers.

The Company’s ten-year franchise with the City of El Paso (“City”) expires on August 1, 2005. The franchise governs the Company’s usage of City-owned property, including the payment of franchise fees.

The Company is meeting with the City to discuss the Company’s franchise and rate treatment after the expiration of the Freeze Period. The Company is unable to predict the outcome of these discussions.

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.

The Company reconciled its Texas jurisdictional fuel costs for the period January 1, 1999 through December 31, 2001 in PUC Docket No. 26194, and on May 5, 2004, the Texas Commission issued its final order. At issue was the Company’s request to recover an additional $15.8 million, before interest, from its Texas customers as a surcharge due to fuel undercollections from January 1999 through December 2001. The Texas Commission disallowed approximately $4.5 million of Texas jurisdictional

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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. This disallowance was recorded as a reduction of fuel revenue during the fourth quarter of 2003. 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 period in which the imputed capacity charges were deemed to have been incurred, the $4.2 million of imputed capacity charges were therefore permanently disallowed, and not recoverable from its Texas customers. The Texas Commission’s decision has been appealed by two parties and the Company, and the Company is unable to predict the ultimate outcome of the appeals.

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 recently commenced a generic rulemaking proceeding to determine a statewide policy for the appropriate pricing of capacity in purchased power contracts. On August 31, 2004, the Company filed an application (PUC Docket No. 30143) to reconcile Texas jurisdictional fuel costs for the period January 1, 2002 to February 29, 2004. There can be no assurance as to the outcome of the rulemaking and its potential impact on the Company with respect to fuel recovery in future reconciliation periods, including those in PUC Docket No. 30143.

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 rewards for the reporting periods ending in 2004, 2003 and 2002 to be approximately $0.2 million, $0.8 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 or comparable evidence of collectibility is obtained. 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.

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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 if it ultimately transitions to retail competition in Texas.

New Mexico Rate Stipulation. On June 1, 2004, the Company implemented new rates according to 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 not collected in base rates; (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; 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.

Fuel. In April 2004, the New Mexico Commission, as part of the New Mexico Stipulation, approved a fuel and purchased power cost adjustment clause. The Company will continue to recover fuel and purchased power costs in base rates in the amount of $0.01949 per kWh and continue the fuel and purchased power cost adjustment to recover 90% of the remaining fuel and purchased power costs. Fuel and purchased power costs associated with the remaining 10% of the Company’s jurisdictional retail sales in New Mexico are fixed at $0.021 per kWh. The Company and all intervenors entered into the New Mexico Stipulation on the Company’s compliance filing.

Renewables. The New Mexico Renewable Energy Act of 2004 requires that, by January 1, 2006, renewable energy comprise no less than 5% of the Company’s total retail sales to New Mexico customers. The requirement increases by 1% annually until January 1, 2011, when the renewable portfolio standard shall reach a level of 10% of the Company’s total retail sales to New Mexico customers and will remain fixed at such level thereafter. On September 1, 2004, the Company filed its Transitional Procurement Plan detailing its proposed actions to comply with the Renewable Energy Act.

The New Mexico Commission approved the Company’s Transitional Procurement Plan with modifications to shorten the term for the Company’s proposed contract to purchase renewable energy credits and to address diversity provisions of the Renewable Energy Act. These modified provisions will be incorporated into the renewable procurement plan to be filed by the Company no later than September 1, 2005 for the 2006 year. Costs incurred by the Company to meet the requirements of the New Mexico Renewable Energy Act are to be recovered from New Mexico customers pursuant to the Renewable Energy Act and the New Mexico Commission’s rules.

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.

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Power Sales Contracts

On November 9, 2004, the Company entered into transactions for the sale of 50 MW to be supplied during the off-peak periods in 2005. The revenues from these sales are anticipated to be approximately $8.2 million in 2005.

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 2004 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 through 2005 at the Eddy County tie and concurrently receive the same amount 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 largest franchise agreement is with the City. The franchise agreement includes a 2% annual franchise fee (approximately $7.9 million per year currently) and allows the Company to utilize public rights-of-way necessary to serve its retail customers within the City. The franchise with the City extends through August 1, 2005.

The Company’s franchise agreement with the City included 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. To exercise the option, the City was required to deliver written notice to the Company one year prior to the expiration of the franchise term. The option expired unexercised on August 1, 2004.

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 $1.2 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 contracts with all three military bases that it serves. The Company signed a

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contract with Ft. Bliss in December 1998 under which Ft. Bliss will take retail electric service from the Company through December 2008. The Company has a contract to provide retail electric service and limited wheeling services to Holloman for a ten-year term which expires in December 2005. In May 1999, the Army and the Company entered into a ten-year contract to provide retail electric service to White Sands.

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Risk Factors

Like other companies in our industry, our consolidated financial results will be impacted by weather, the economy of our service territory, fuel prices, the performance of our customers and the decisions of regulatory agencies. Our common stock price and creditworthiness will be affected by national and international macroeconomic trends, general market conditions and the expectations of the investment community, all of which are largely beyond our control. In addition, the following statements highlight risk factors that may affect our consolidated financial condition and results of operations. These are not intended to be an exhaustive discussion of all such risks, and the statements below must be read together with factors discussed elsewhere in this document and in our other filings with the SEC.

Our Costs Could Increase if There are Problems

at the Palo Verde Nuclear Generating Station

A significant percentage of our generating capacity, assets and operating expenses is attributable to Palo Verde. The Company’s 15.8% interest in each of the three Palo Verde units total approximately 600 MW of generating capacity. Palo Verde represents approximately 40% of our available net generating capacity and represented approximately 49% of our available energy for the twelve months ended December 31, 2004. Nuclear fuel represented approximately 49% of the total kWh energy mix of the Company for the twelve months ended December 31, 2004. We face 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 prior to the expiration of the Freeze Period in the event of increases in non-fuel costs or loss of revenue. Additionally, should retail competition occur, 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.

Our Retail Rates Are Subject to Change Following the

Termination of our Ten-Year Rate Freeze in August 2005

Our rates in Texas, which account for 68% of our revenues, have been frozen and not subject to regulatory review since August 2, 1995. The Freeze Period expires on August 1, 2005. Thereafter, we will be subject to traditional cost of service regulation by the Texas cities that we serve and the Texas Commission. There can be no assurance that we will be able to maintain our Texas rates after expiration of the Freeze Period. In addition, the end of the Freeze Period may mean that we will no longer be entitled to retain 50% of our margins from off-system sales. If a return to cost of service regulation leads to lower rates or the retention by us of less of the margin from off-system sales, there would be a material negative impact on our revenues, earnings, cash flows and financial position.

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Our Franchise With the City of El Paso

Expires in August 2005

El Paso is the largest city in our service area, representing 59% of our revenues for the twelve months ended December 31, 2004. Our ten-year franchise with the City of El Paso expires on August 1, 2005 and there can be no assurance that we will be able to negotiate a new franchise on terms that are acceptable to us.

We May Not Be Able to Pass Through

All of Our Fuel Expenses to Customers

In general, through regulation, we can pass through our fuel and purchased power expenses to our customers. Nevertheless, we agreed in 2004 to a fixed fuel factor for ten percent of our retail customers in New Mexico. This subjects us to the risk of increased costs of fuel that would not be recoverable. The portion of fuel expense that is not fixed is subject to reconciliation by the Texas and New Mexico Commissions. Prior to the completion of a reconciliation, the Company records fuel transactions such that fuel revenues equal fuel expense except for the portion fixed in New Mexico. In the event that a disallowance occurs during a reconciliation proceeding, the amounts recorded for fuel and purchased power expenses could differ from the amounts allowed to be collected by us from our customers and we would incur a loss to the extent of the disallowance.

Equipment Failures and Other External Factors

Can Adversely Affect Our Results

The generation and transmission of electricity require the use of expensive and complex equipment. While we have a maintenance program in place, generating plants are subject to unplanned outages because of equipment failure. We are particularly vulnerable to this due to the advanced age of several of our generating units in or near El Paso. In these events, we must acquire power from others at unpredictable costs in order to supply our customers and comply with our contractual agreements. This can increase our costs materially and prevent us from selling excess power at wholesale, thus reducing our profits. In addition, decisions or mistakes by other utilities may adversely affect our ability to use transmission lines to deliver or import power, thus subjecting us to unexpected expenses or to the cost and uncertainty of public policy initiatives. We are particularly vulnerable to this because a significant portion of our available energy (at Palo Verde and Four Corners) is located hundreds of miles from El Paso and Las Cruces and must be delivered to our customers over long distance transmission lines. These factors, as well as weather, interest rates, economic conditions, fuel prices and price volatility, are largely beyond our control, but may have a material adverse effect on our consolidated earnings, cash flows and financial position.

Competition and Deregulation Could Result in a

Loss of Customers and Increased Costs

As a result of changes in federal law, our wholesale and large retail customers already have, in varying degrees, alternate sources of economical power, including co-generation of electric power. In addition, in recent years, both New Mexico and Texas passed industry deregulation legislation requiring us to separate our transmission and distribution functions, which would remain regulated, from our

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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. On October 13, 2004, the Texas Commission approved a rule delaying retail competition in the Company’s Texas service territory. There is substantial uncertainty about both the regulatory framework and market conditions that would exist if and when retail competition is implemented in the Company’s Texas service territory, and we may incur substantial preparatory, restructuring and other costs that may not ultimately be recoverable. There can be no assurance that deregulation would not adversely affect our future operations, cash flows and financial condition.

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Executive Officers of the Registrant

The executive officers of the Company as of February 28, 2005, 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. 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 and certain warehouse facilities in El Paso, Texas under a lease which expires in January 2006 with two concurrent renewal options of six months each.

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, except as described below, none of these claims will have a material adverse effect on the financial position, results of operations or 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. 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. On April 13, 2004, the Court granted a motion of the Company and the remaining individual defendants requesting permission to file an interlocutory appeal to the U. S. Court of Appeals for the Fifth Circuit regarding certain legal questions relating to the Court’s denial of the motion to dismiss the complaint as to those defendants. On April 27, 2004, the Court entered an order staying the district court proceedings until the Fifth Circuit completed its review. On June 7, 2004, the U. S. Court of Appeals denied the appeal which automatically lifted the stay in the district court. This matter is presently set for trial on September 19, 2005, but such date may be extended. While the Company believes the lawsuit is without merit and intends to defend itself vigorously, the Company is unable to predict the outcome or the range of any possible loss.

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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 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. The Company, together with several other defendants, filed a motion to dismiss. On May 12, 2004, the Court granted the Company’s motion, and the suit was dismissed. The Port of Seattle has filed an appeal of the Court’s decision with the U. S. Court of Appeals for the Ninth Circuit. The parties have filed briefs and are awaiting a hearing and decision. While the Company believes that these matters are without merit, the Company is unable to predict the outcome or range of any possible loss.

On November 3, 2003, TNP filed a complaint against the Company with the FERC, asking the FERC to make a determination that TNP has certain “rollover rights” to network-type transmission service over the Company’s transmission system as a result of a power sales agreement between it and the Company which expired at the end of 2002. TNP asserted that it has such rights under the rollover provisions of FERC Order No. 888. The Company responded to TNP’s complaint by contesting TNP’s assertion of rollover rights on several grounds. Due to existing transmission constraints, a FERC ruling granting TNP’s complaint could have adversely impacted the Company’s ability to import lower cost power from Palo Verde and Four Corners to serve its retail customers, which could have resulted in higher rates for the Company’s retail electric customers. A hearing on this matter before an administrative law judge (“ALJ”) was held on July 19 and 20, 2004, and, on September 20, 2004, the ALJ issued a proposed decision, dismissing TNP’s complaint and concluding that TNP has no rollover rights over the Company’s transmission system. On March 2, 2005, the Commission issued its order affirming the dismissal of TNP’s complaint.

On June 29, 2004, the Company filed suit against TNP in the Third Judicial District Court of New Mexico, claiming that TNP acted in bad faith by claiming such transmission rights and seeking to obtain use of more transmission rights than originally allocated to TNP under its original contract with the Company. The Company seeks both actual and exemplary damages from TNP as well as a declaration that TNP breached its agreements with the Company, acted in bad faith and violated New Mexico law prohibiting such actions. On November 1, 2004, the Company filed a motion for leave to amend the complaint to add PNM as a defendant in this action, alleging, among other things, that PNM tortiously interfered with the Company’s contractual relationships with TNP. On November 22, 2004, the Company, TNP and PNM entered into a settlement agreement (contingent upon FERC approval) whereby (i) TNP would withdraw its complaint against the Company with the FERC and no longer seek certain rollover transmission rights from the Company; (ii) the Company would dismiss its claims against TNP and PNM in the New Mexico district court; and (iii) TNP would reimburse the Company for certain costs incurred in defending the FERC action. On March 2, 2005, the settlement was approved by the FERC.

On May 5, 2004, Wah Chang, a specialty metals manufacturer which operates a plant in Oregon, filed suit against the Company and other defendants in the United States District Court for the District of

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Oregon. (Wah Chang v. Avista Corporation, et al., No. 04-619AS). The complaint makes substantially the same allegations as were made in Port of Seattle and seeks the same types of damages. In addition, on June 7, 2004, the City of Tacoma filed suit against the Company and other defendants in the United States District Court for the Western District of Washington (City of Tacoma v. American Electric Power Service Corp., et al., C04-5325RBL). This complaint also makes substantially the same allegations as were made in Port of Seattle and seeks civil damages (including treble damages) from the Company and the other defendants for violations of certain antitrust provisions under the Sherman Act. Both of these matters were transferred to the same court that heard and dismissed the Port of Seattle lawsuit and on February 11, 2005, the Court granted the Company’s motion to dismiss both cases. Wah Chang and the City of Tacoma have thirty days in which to appeal the Court’s decision with the U.S. Court of Appeals for the Ninth Circuit. While the Company believes that these matters are without merit, the Company is unable to predict the outcome or range of any possible loss.

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

No matter was submitted to vote of the Company’s security holders through the solicitation of proxies or otherwise during the fourth quarter of 2004.

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PART II

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

The Company’s common stock trades on the New York Stock Exchange under the symbol “EE.” 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 for the periods indicated below were as follows:

As of February 28, 2005, there were 4,456 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 stock repurchase programs and to repurchase debt with coupons in excess of market rates when it is economically advantageous to do so, with the goal of maintaining or improving its capital structure, bond ratings, and earnings per share.

Since the inception of the stock repurchase programs in 1999, the Company has repurchased approximately 15.3 million shares in total at an aggregate cost of $175.6 million, including commissions. During 2004, the Company repurchased 294,842 shares of common stock for $4.5 million, including commissions, pursuant to the two million share buyback program authorized by its Board of Directors in February 2004. An additional 1,705,158 shares are authorized to be repurchased under the program. No shares were repurchased during the fourth quarter of 2004. The Company may continue making purchases of its stock pursuant to its stock repurchase plan 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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Item 6. Selected Financial Data

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

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

As you read this Management’s Discussion and Analysis, please refer to the Company’s Consolidated Financial Statements and the accompanying notes, which contain the Company’s operating results.

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 policies and 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:

SFAS No. 71

Regulated electric utilities typically prepare their financial statements in accordance with SFAS No. 71. Under this accounting standard, certain recoverable costs are shown as either assets or liabilities on a utility’s balance sheet if the regulator provides assurance that these costs will be charged to and collected from its customers (or has already permitted such cost recovery). The resulting regulatory assets or liabilities are amortized in subsequent periods based upon their respective amortization periods in a utility’s cost of service.

Beginning in 1991, the Company discontinued the application of SFAS No. 71 to its financial statements. This decision was based on the Company’s determination that its rates were no longer designed to recover its costs of providing service to customers. Upon emerging from bankruptcy in 1996, the Company again concluded that it did not meet the criteria for applying SFAS No. 71 because of the ten-year rate freeze in Texas and its ongoing intention not to seek changes in its New Mexico rates, which had been established in 1990. Although the Company believes the rates established in 1995 were based upon its costs of service, the unusual length of the rate freeze period created substantial uncertainty as to the ultimate recovery of its costs over the entire freeze period. Consequently, the Company determined that it should not re-apply SFAS No. 71 to its Texas jurisdiction at the time it emerged from bankruptcy in February 1996. As the freeze period draws to a close, the Company will continue to evaluate whether it meets the criteria for the re-application of SFAS No. 71 to its Texas jurisdiction.

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During 2004, the Company determined that it met the criteria necessary to re-apply SFAS No. 71 to its New Mexico jurisdictional operations. For the New Mexico jurisdiction, two key events transpired that, when considered together, resulted in the Company’s decision to re-apply SFAS No. 71. In April of 2004, the Company received a final order approving a unanimous stipulation which established new base and fuel rates for its New Mexico customers which were implemented June 1, 2004. The Company’s approved rates were based upon its cost of providing service in New Mexico. That event, coupled with

the repeal of New Mexico’s electric utility industry restructuring law which occurred in April of 2003, resulted in the Company meeting the criteria for the re-application of SFAS No. 71 to New Mexico, beginning July 1, 2004. The re-application of SFAS No. 71 to the Company’s New Mexico jurisdiction resulted in the recording of $18.5 million of regulatory assets, $5.0 million in related accumulated deferred income tax assets, $16.2 million of regulatory liabilities, $5.5 million in related accumulated deferred tax liabilities and a $1.8 million extraordinary gain, net of tax, or $0.04 basic and diluted earnings per share. The Company’s continued ability to meet the criteria for the application of SFAS No. 71 for the New Mexico jurisdiction may be affected in the future by competitive forces and restructuring in the electric utility industry. In the event that SFAS No. 71 no longer applies to the New Mexico jurisdiction, the related regulatory assets and liabilities would be written off unless an appropriate regulatory recovery mechanism is provided.

Collection of Fuel Expense

In general, through regulation, the Company’s fuel and purchased power expenses are passed through to its 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 transactions such that fuel revenues equal fuel expense except for the portion fixed in New Mexico. In the event that a disallowance occurs during a reconciliation proceeding, the 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

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collect before the expiration of the Freeze Period substantially all costs that would otherwise be “stranded” under relevant laws in Texas and that future net cash flows after the expiration of the Freeze Period from the generating assets will be sufficient to recover their net book values.

Decommissioning Costs and Estimated Asset Retirement Obligation

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 and associated common areas. The Company recorded a liability and a corresponding asset for the fair value of its decommissioning obligation (ARO) upon implementation of SFAS No. 143. The Company will adjust the liability to its present value periodically over time, and the corresponding asset will be depreciated over its useful life. The determination of the estimated liability requires the use of various assumptions pertaining to decommissioning costs, escalation and discount rates.

The Company and other Palo Verde Participants rely upon decommissioning cost studies and make discount 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 decommissioning 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 costs 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 decommissioning. Should the Company become subject to the Texas Restructuring Law, the Company expects to continue to be able to collect from customers the costs of decommissioning.

Future Pension and Other Postretirement Obligations

The Company’s obligations to retirees under various benefit plans are recorded as a liability on the consolidated balance sheets. This liability is calculated on the basis of significant assumptions regarding discount rate, expected return on plan assets, rate of compensation increase and health care cost inflation. These assumptions as well as a sensitivity analysis of the effect of hypothetical changes in certain assumptions are set forth in detail in Note K “Employee Benefits” to the Notes to Consolidated Financial Statements. Changes in these assumptions could have a material impact on both net income and on the amount of liabilities reflected on the consolidated balance sheets.

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In developing the assumptions, management makes judgments based on the advice of financial and actuarial advisors and its review of third-party and market-based data. These sources include life expectancy tables, surveys of compensation and health care cost trends, and historical and expected return data on various categories of plan assets. The assumed discount rate applied to future plan obligations is based at each measuring date on prevailing market interest rates inherent in high quality (AA and better) corporate bonds that would provide future cash flow needed to pay the benefits as they become due, as well as on publicly available bond issues. The Company regularly reviews its assumptions and conducts a reassessment at least once a year. The Company does not expect that any such change in assumptions will have a material effect on net income for 2005.

Reserves for Tax Dispute

The Company received final approval from the IRS during the third quarter of 2004 to settle all issues relative to its 1996 through 1998 federal income tax returns. As part of the settlement, the Company was required to capitalize (for tax purposes) approximately twenty percent of the previously claimed lease rejection damage deductions. In addition, the IRS conceded the litigation settlement issue related to a terminated merger agreement. As a result of the IRS settlement, the Company reduced its estimated contingent tax liability by $3.5 million related to the resolution of certain tax contingency items and adjusted its state deferred tax liabilities (net of federal tax benefit) by $2.7 million. The IRS settlement reduced income tax expense by approximately $6.2 million during 2004, which increased net income for such period by the same amount. The IRS is currently performing an examination of the 1999 through 2002 income tax returns. 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 of the ongoing examination cannot be predicted with certainty, and while the contingent tax liability may not in fact be sufficient, the Company believes that the amount of contingent tax liability recorded as of December 31, 2004 is a reasonable estimate of any additional tax that may be due.

Overview

The Company derives revenue principally from the sale of power to retail and wholesale customers (including economy sales), which accounted for 87% and 11%, respectively, of the Company’s revenues for the year ended December 31, 2004, and 87% and 12%, respectively, of the Company’s revenues for the year ended December 31, 2003. Revenues from the sale of electricity include fuel costs, which are passed through directly to customers, and base revenues. Base revenues refers to the Company’s revenues from the sale of electricity excluding such fuel costs. Economy sales, which are sales into markets outside the Company’s service territory, represented 11% and 12% of revenues for the years ended December 31, 2004 and 2003, respectively.

The Company’s retail customers consist of residential customers, small commercial and industrial customers, large commercial and industrial customers and public authorities, which accounted for 38%, 36%, 10% and 16%, respectively, of the Company’s retail base revenues for the years ended December 31, 2004 and 2003. Sales for resale base revenues consist of sales pursuant to a long-term power contract for the year ended December 31, 2004. For the year ended December 31, 2003, sales for resale base revenues consist of sales pursuant to a long-term power contract and sales to CFE, which accounted for 59% and 41%, respectively, of the Company’s sales for resale base revenues. Sales to the

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Company’s largest wholesale customer, Rio Grande Electric Cooperative, accounted for 0.4% of the Company’s base revenues for the years ended December 31, 2004 and 2003. No retail customer accounted for more than 3% of the Company’s base revenues during such periods.

The Company’s business is seasonal, with higher revenues during the summer cooling season. The following table sets forth the percentage of the Company’s revenues derived during each quarter for the periods presented:

Palo Verde, which represents approximately 40% of the Company’s available net generating capacity and approximately 49% of the Company’s available energy for the twelve months ended December 31, 2004, is subject to performance standards in Texas. If such performance standards are not met, the Company is subject to a penalty. See “Business–Regulation–Texas Regulatory Matters–Palo Verde Performance Standards.”

Historical Results of Operations

Income before the extraordinary item and cumulative effect of accounting change increased $13.0 million, or $0.27 diluted earnings per share in 2004 compared to the restated results for 2003. This after-tax increase resulted primarily from (i) the 2003 asset impairment loss of $10.7 million on the Customer Information System (“CIS”) project with no comparable loss in the current period; (ii) the recording of the benefits of the IRS settlement of $6.2 million in 2004 with no comparable amounts in 2003; (iii) decreased 2004 non-Palo Verde maintenance expense of $3.3 million; (iv) the Texas fuel disallowance in Docket No. 26194 of $2.8 million that was recorded in 2003 with no comparable amount in the current period; (v) increased 2004 retail sales of $1.9 million; (vi) the extraordinary gain

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in 2004 of $1.8 million related to the re-application of SFAS No. 71 to the Company’s New Mexico jurisdictional operations; and (vii) a 2003 accrual for a gas contract termination charge of $0.9 million with no comparable amount in the current period. These increases in earnings were partially offset by (i) increased 2004 pensions and benefits expense of $3.8 million (including an employee bonus in 2004 with no comparable amount in 2003); (ii) increased 2004 depreciation and amortization expense of $3.6 million; (iii) increased 2004 loss on extinguishments of debt of $3.3 million; (iv) increased 2004 Palo Verde operations and maintenance expense of $2.6 million (including a Palo Verde employee annual bonus with no comparable amount in 2003); and (v) an increase in the coal reclamation liability in 2004 of $1.5 million.

The pro forma net income and earnings per share amounts shown above assume SFAS No. 143 had been applied on a retroactive basis.

Income before the extraordinary item and cumulative effect of accounting change decreased $13.0 million, or $0.24 diluted earnings per share in 2003 compared to the pro forma results for 2002. This after-tax decrease resulted primarily from (i) decreased 2003 wholesale sales revenue of $17.0 million primarily related to the expiration of two long-term contracts; (ii) the impairment loss on the CIS project of $10.7 million recorded in 2003 with no comparable amount in 2002; (iii) increased 2003 pension and benefits expenses of $3.1 million; (iv) Texas fuel disallowance of $2.8 million recorded in 2003 with no comparable amount in 2002; (v) increased 2003 insurance expenses of $2.8 million; (vi) increased 2003 outside services of $2.2 million; and (vii) increased 2003 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 2003 sales and margins on economy sales of $6.3 million; (iii) increased 2003 retail sales of $5.6 million; (iv) decreased 2003 interest on long-term debt of $2.3 million; (v) decreased 2003 loss on extinguishments of debt of $2.1 million; and (vi) decreased 2003 MiraSol operating loss of $1.9 million.

Operating revenues net of energy expenses increased $4.4 million in 2004 compared to 2003 primarily due to the Texas fuel disallowance in Docket No. 26194 of $4.5 million that was recorded in 2003 with no comparable amount in the current period and increased 2004 retail sales of $3.1 million, partially offset by an increase of $2.4 million in 2004 coal reclamation liability.

Operating revenues net of energy expenses decreased $16.4 million in 2003 compared to 2002 primarily due to (i) decreased 2003 wholesale sales of $25.5 million; (ii) Texas fuel disallowance of $4.5 million recorded in 2003 with no comparable amount in 2002; and (iii) a 2003 $4.0 million decrease in revenue from the energy service operations partially offset by increased 2003 sales and margins on economy sales of $10.3 million and increased 2003 retail sales of $9.2 million.

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

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