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.
Index to Financial Statements 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
Index to Financial Statements
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
Index to Financial Statements
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
Index to Financial Statements
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.
Index to Financial Statements 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.
Index to Financial Statements 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
Index to Financial Statements
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.
(1) Does not include acquisition costs for nuclear fuel. See “Energy Sources - Nuclear Fuel.”
(2) Includes $159.6 million for local generation, $15.4 million for the Four Corners Station and $109.4 million for the Palo Verde Station.
Index to Financial Statements 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.
Index to Financial Statements 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.
Index to Financial Statements
(1) Revised to conform with new 2004 commercial and industrial large billing system which counts customers by service location rather than by meter. This change did not affect sales or revenues of the Company.
(2) Includes spot firm sales of 245,000 kW, 355,000 kW and 150,000 kW for 2004, 2003 and 2002, respectively.
(3) Excludes 103,000 kW, 103,000 kW and 153,000 kW of firm on and off-peak purchases for 2004, 2003 and 2002, respectively.
(4) System capacity factor includes average firm system purchases of 103,000 kW, 103,000 kW and 143,000 kW for 2004, 2003 and 2002, respectively.
Index to Financial Statements 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
Index to Financial Statements
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.
Index to Financial Statements 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
Index to Financial Statements
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.
Index to Financial Statements 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.
Index to Financial Statements 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
Index to Financial Statements
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.
Index to Financial Statements 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.
Index to Financial Statements 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
Index to Financial Statements
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.
Index to Financial Statements Executive Officers of the Registrant
The executive officers of the Company as of February 28, 2005, were as follows:
(1) On March 4, 2005, Mr. Bassham announced his resignation from the Company, effective as of March 18, 2005, to accept a similar position with another public utility company.
The executive officers of the Company are elected annually and serve at the discretion of the Board of Directors.
Index to Financial Statements
Item 2.
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.
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.
Index to Financial Statements 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
Index to Financial Statements
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.
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.
Index to Financial Statements
PART II
Item 5.
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.
Index to Financial Statements
Item 6.
Item 6. Selected Financial Data
As of and for the following periods (in thousands except for share data)
Index to Financial Statements
Item 7.
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
•
Collection of fuel expense
•
Value of net utility plant in service
•
Decommissioning costs and estimated asset retirement obligation
•
Future pension and other postretirement obligations
•
Reserves for tax dispute
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.
Index to Financial Statements
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
Index to Financial Statements
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.
Index to Financial Statements 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
Index to Financial Statements
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
Index to Financial Statements
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.
Index to Financial Statements Comparisons of kWh sales and operating revenues are shown below (in thousands):
(1) Primarily due to 2003 CFE wholesale power sales with no comparable sales in 2004.
(2) Primarily due to an increase in recoverable fuel expenses as a result of an increase in the price and volume of natural gas burned and an increase in purchased power costs.
(3) Primarily due to higher margins.
(4) Represents revenues with no related kWh sales.
(5) Primarily due to increased transmission revenues.
Index to Financial Statements
(1) Primarily due to the expiration of a wholesale power contract with IID on April 30, 2002 and TNP on December 31, 2002, and reduced sales to the CFE.
(2) Primarily due to increased available power as a result of the expiration of the wholesale contracts mentioned above and higher prices in the economy market.
(3) Primarily due to the expiration of wholesale power contracts with IID and TNP, decreased energy expenses passed through to Texas and New Mexico customers, and reduced sales to the CFE.
(4) Primarily due to decreased energy services revenues.
(5) Represents revenues with no related kWh sales.
Other operations expense increased $5.5 million in 2004 compared to 2003 primarily due to increased pension and benefits expense of $6.1 million (including a $3.2 million increase in employee bonuses), and increased Palo Verde operations expense of $1.7 million. These increases were partially offset by decreased insurance-related expenses of $1.5 million and decreased customer accounts expense of $1.5 million.
Index to Financial Statements Other operations expense increased $14.6 million in 2003 compared to 2002 primarily due to (i) increased pension and benefits expense of $5.0 million resulting from declines in the financial markets; (ii) accretion expense of $4.8 million related to the implementation of SFAS No. 143; (iii) increased insurance related expenses of $4.5 million; (iv) increased legal and consulting fees of $3.7 million; and (v) increased Palo Verde expense of $3.4 million. These increases were partially offset by decreased energy services operations expense of $7.2 million primarily due to a warranty reserve recorded by the Company in 2002 and the cessation of additional marketing activities by MiraSol in 2002.
The Company abandoned the CIS project and recognized an asset impairment loss of $17.6 million in September 2003. The Company is now analyzing various options to meet its current and projected CIS needs.
The FERC settlements relate to the settlements with the FERC Trial Staff and principal California parties pursuant to which the Company agreed to refund $15.5 million of revenues it earned on wholesale power transactions in 2000 and 2001. These settlements were recorded in December 2002.
Maintenance expense decreased $3.1 million in 2004 compared to 2003 primarily due to a decrease in non-Palo Verde maintenance expense of $5.4 million offset by increased maintenance at Palo Verde of $2.4 million due to the timing of scheduled refueling and maintenance outages.
Maintenance expense increased slightly in 2003 compared to 2002 primarily due to maintenance outages in 2003 at local generating stations of $1.7 million offset by reduced maintenance at Palo Verde of $1.2 million due to the timing of scheduled refueling and maintenance outages.
Depreciation and amortization expense increased $5.8 million in 2004 compared to 2003 primarily due to depreciation on the new Palo Verde Unit 2 steam generators of $2.2 million, the implementation of new depreciation rates based on a new depreciation study resulting in an increase of $1.9 million and increased other depreciable plant balances resulting in an increase of $1.7 million. Depreciation and amortization expense decreased $2.4 million in 2003 compared to 2002 primarily due to decreased depreciation expense of $3.7 million resulting from the adoption of SFAS No. 143.
Taxes other than income taxes remain relatively unchanged in 2004 compared to 2003. Taxes other than income taxes decreased by $0.5 million in 2003 compared to 2002 due to a decrease in property tax.
Other income (deductions) decreased $5.1 million in 2004 compared to 2003 primarily due to (i) losses on extinguishments of debt of $5.4 million recorded in 2004 with no comparable activity in 2003; (ii) $1.1 million reduction in interest income in 2004 associated with the resolution of the Texas fuel reconciliation in PUC Docket No. 26194; and (iii) $1.0 million related to certain tax refunds received in 2003 with no comparable amount in 2004. These decreases were partially offset by an increase of $2.4 million in investment and interest income related to the decommissioning trust fund.
Other income (deductions) increased $6.9 million in 2003 compared to 2002 primarily due to losses on extinguishments of debt of $3.4 million recorded in 2002 with no comparable activity in 2003
Index to Financial Statements
and increased investment and interest income of $2.8 million primarily related to the decommissioning trust fund.
Interest charges (credits) decreased slightly in 2004 compared to 2003 primarily due to decreased interest expense of $2.2 million due to a reduction of outstanding debt as a result of open market purchases of the Company’s first mortgage bonds partially offset by a reduction in capitalized interest of $2.1 million as a result of transferring Palo Verde Unit 2 steam generators to plant in service. Interest charges decreased $11.8 million in 2003 compared to 2002 primarily due to (i) an $8.3 million decrease resulting from the adoption of SFAS No. 143 and (ii) a $3.5 million decrease resulting from a reduction of outstanding debt as a result of open market purchases of the Company’s first mortgage bonds.
Income tax expense, before the tax effect of an extraordinary item, decreased $4.0 million in 2004 compared to 2003 primarily due to the $6.2 million benefit from the IRS settlement offset by changes in pretax income and certain permanent differences and adjustments. Income tax expense, before the tax effect of a cumulative effect of accounting change, decreased $3.3 million in 2003 compared to 2002 primarily due to changes in pretax income and certain permanent differences and adjustments.
Extraordinary gain on re-application of SFAS No. 71 relates to the Company’s 2004 third quarter determination that it met the criteria necessary to re-apply SFAS No. 71 to its New Mexico jurisdiction. The decision was based on the Company’s receiving the New Mexico Commission’s approval for new rates that were based upon the Company’s cost of service and the fact that New Mexico had repealed its electric utility restructuring law. The re-application of SFAS No. 71 to the Company’s New Mexico jurisdiction resulted in the recording of a $1.8 million extraordinary gain.
The cumulative effect of accounting change relates to the adoption of SFAS No. 143 on January 1, 2003. SFAS No. 143 provides guidance on the recognition and measurement of liabilities associated with the retirement of tangible long-lived assets. SFAS No. 143 affected the accounting for the decommissioning of the Company’s Palo Verde and Four Corners Stations and changed the method used to report the decommissioning obligation.
In November 2004, the FASB issued SFAS No. 151, “Inventory Costs” - an amendment of Accounting Research Bulletin No. 43, (“ARB No. 43”), (“Inventory Pricing”). ARB No. 43 previously stated that “under some circumstances, items such as idle facility expense, excessive spoilage, double freight and rehandling costs may be so abnormal as to require treatment as current period charges.” SFAS No. 151 requires that those items be recognized as current-period charges regardless of whether they meet the criterion of “so abnormal.” The provisions of this statement are effective for inventory costs incurred during fiscal years beginning after June 15, 2005. The Company does not believe SFAS No. 151 will have a significant impact on the Company’s consolidated financial statements.
In December 2004, the FASB issued SFAS No. 153, “Exchanges of Nonmonetary Assets” - an amendment of Accounting Principles Board Opinion No. 29 (“APB No. 29”), “Accounting for Nonmonetary Transactions.” The guidance in APB No. 29 is based on the principle that exchanges of nonmonetary assets should be measured based on the fair value of the assets exchanged, with certain exceptions. SFAS No. 153 eliminates the exception for nonmonetary exchanges of similar productive assets and replaces it with a general exception for exchanges of nonmonetary assets that do not have
Index to Financial Statements
“commercial substance.” A nonmonentary exchange has “commercial substance” if the future cash flows of the entity are expected to change significantly as a result of the exchange. The provisions of this statement are effective for fiscal periods beginning after June 15, 2005. The Company does not believe SFAS No. 153 will have a significant impact on the Company’s consolidated financial statements.
In December 2004, the FASB issued a revision of SFAS No. 123, “Accounting for Stock-Based Compensation.” SFAS No. 123 (revised) focuses primarily on accounting for transactions in which an entity obtains employee services in share-based payment transactions. SFAS No. 123 (revised) requires a public entity to measure the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award (with some limited exceptions). That cost will be recognized over the period during which an employee is required to provide service in exchange for the award - “the requisite service period” - typically the vesting period. No compensation cost is recognized for equity instruments for which employees do not render the requisite service. SFAS No. 123 (revised) is effective for public entities that do not file as small business issuers as of the beginning of the first interim or annual reporting period that begins after June 15, 2005. SFAS No. 123 (revised) applies to all awards granted after the required effective date and to awards modified, repurchased or cancelled after that date. Additionally, compensation cost for outstanding awards for which the requisite service has not been rendered as of the effective date shall be expensed as the requisite service is rendered on or after the required effective date. The compensation cost for that portion of awards shall be based on the grant-date fair value of those awards as calculated for pro forma disclosure under SFAS No. 123. Due to timing of the release of SFAS No. 123 (revised), the Company has not yet completed the analysis of the ultimate impact that this new pronouncement will have on the Company’s financial statements but does not expect this statement to have an effect materially different than the pro forma disclosures provided in Note A to the Company’s consolidated financial statements.
Under SFAS No. 71, regulated electric utilities show certain recoverable costs 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. The Company’s Texas jurisdiction has been operating under a rate freeze since August 2, 1995. The rate freeze is for a ten-year period which expires on July 31, 2005. 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.
For the last several years, inflation has been relatively low and, therefore, has had little impact on the Company’s results of operations and financial condition.
Index to Financial Statements Liquidity and Capital Resources
The Company’s principal liquidity requirements in the near-term are expected to consist of the refinancing of the Company’s pollution control bonds and its first mortgage bonds, interest payments on the Company’s indebtedness, operating and capital expenditures related to the Company’s generating facilities and transmission and distribution systems, and income and other taxes. The Company expects that, for all but the debt refinancing, cash flows from operations will be sufficient for such purposes. As of December 31, 2004, the Company had approximately $29.4 million in cash and cash equivalents, a decrease of $5.0 million from the balance of $34.4 million on December 31, 2003.
The Company’s contractual obligations as of December 31, 2004 are as follows (in thousands):
(1) The Company’s 8.9% Series D First Mortgage Bonds are due in February 2006.
(2) The pollution control bonds are scheduled for remarketing on August 1, 2005.
(3) Interest on nuclear fuel is based on actual interest rates at the end of 2004.
(4) Amount is based on the minimum volumes per the contract and market price at the end of 2004.
(5) Some of the nuclear fuel contracts are based on a fixed price adjusted for an index. The index used is the current index at the end of 2004.
(6) These obligations include the Company’s minimum contractual funding requirements for the non-qualified retirement income plan and the other postretirement benefits for 2005. The Company has no minimum contractual funding requirement related to its retirement income plan for 2005. However, the Company may decide to fund at a higher level than the minimum contractual funding amounts and expects to contribute $18.5 million and $3.4 million to its retirement plans and postretirement benefit plan in 2005, as disclosed in Part II, Item 8, Notes to Financial Statements, Note K, Employee Benefits. Minimum contractual funding requirements for 2006 and beyond are not included due to the uncertainty of interest rates and the related return on assets.
(7) These obligations represent funding requirements under the ANPP Participation Agreement based on the current rate of return on investments.
Index to Financial Statements
(8) The Company has an operating lease for administrative offices which expires in May 2007 and a two-year operating lease for a warehouse which expires in January 2006 with two concurrent renewal options of six months each.
Pollution control bonds of $193.1 million are subject to remarketing on August 1, 2005, and first mortgage bonds of $175.8 million are scheduled to mature in 2006. The Company expects that these obligations will be refinanced through the capital and credit markets. Additionally, the Company has $183.6 million of first mortgage bonds which become callable in 2006 and which may be refinanced at that time if market conditions are favorable. The Company’s ability to access capital and credit markets may be adversely affected by uncertainties related to its operating results, conditions in the credit markets and debt rating agency actions.
Long-term capital requirements of the Company will consist primarily of construction of electric utility plant and the payment of interest on and retirement and refinancing of debt. Utility construction expenditures will consist primarily of expanding and updating the transmission and distribution systems, addition of new generation, and the cost of capital improvements and replacements at Palo Verde and other generating facilities, including the replacement of steam generators in Palo Verde Units 1 and 3. See Part I, Item 1, “Business - Construction Program.”
During the twelve months ended December 31, 2004 and 2003, the Company utilized $74.2 million and generated $0.7 million, respectively, of regular federal tax loss carryforwards. The significant reduction in federal tax loss carryforwards in 2004 was primarily related to the IRS settlement. The Company anticipates that existing regular federal tax loss carryforwards will be fully utilized in 2005 and the Company’s cash flow requirements are expected to include greater amounts of cash for income taxes than has existed in recent years.
The Company is continually evaluating its funding requirements related to its retirement plans, other postretirement benefit plans, and decommissioning trust funds. The Company made contributions of $15.7 million and $9.9 million during the twelve months ended December 31, 2004 and 2003, respectively, to its retirement plans. The Company’s contributions to its other postretirement benefit plans were $3.4 million for both 2004 and 2003. The Company also contributed $5.9 million and $10.4 million to the decommissioning trust funds during the twelve months ended December 31, 2004 and 2003, respectively.
The $100 million revolving credit facility provides up to $70 million for nuclear fuel purchases. Any amounts not borrowed by the Company for nuclear fuel purchases are available for use for working capital needs. As of December 31, 2004, approximately $41.2 million had been drawn for nuclear fuel purchases. No amounts are currently outstanding on this facility for working capital needs. The revolving credit facility was renewed for a five-year term in December 2004.
Since inception of its deleveraging program in 1996, the Company has repurchased or retired with internally generated cash $586.5 million of first mortgage bonds. First mortgage bonds totaling $36.0 million were repurchased in 2004. Common stock equity as a percentage of capitalization, including current portion of long-term debt and financing obligations, was 47% as of December 31, 2004.
Index to Financial Statements Since the inception of the stock repurchase programs in 1999, the Company 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 currently authorized 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.
Off-Balance Sheet Arrangements
The Company has no off-balance sheet arrangements that have or are reasonably likely to have a current or future effect on the Company’s financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources.
Index to Financial Statements
Item 7A.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
The following discussion regarding the Company’s market-risk sensitive instruments contains forward-looking information involving risks and uncertainties. The statements regarding potential gains and losses are only estimates of what could occur in the future. Actual future results may differ materially from those estimates presented due to the characteristics of the risks and uncertainties involved.
The Company is exposed to market risk due to changes in interest rates, equity prices and commodity prices. Substantially all financial instruments and positions held by the Company described below are held for purposes other than trading.
Interest Rate Risk
The Company’s long-term debt obligations are all fixed-rate obligations with varying maturities, except for its revolving credit facility, which provides for nuclear fuel financing and working capital, and is based on floating rates. Interest rate risk, if any, related to the revolving credit facility is substantially mitigated through the operation of the Texas and New Mexico Commission rules which establish energy cost recovery clauses (“fuel clauses”). Under these rules and fuel clauses, energy costs, including interest expense on nuclear fuel financing, except as noted in “Regulation - New Mexico Regulatory Matters - Fuel,” are passed through to customers. Currently, the Company anticipates remarketing its pollution control bonds in 2005 and issuing additional long-term debt to retire the 8.9% Series D First Mortgage Bonds. Additionally, the Company’s 9.4% Series E First Mortgage Bonds become callable and may be refinanced in 2006.
The Company’s decommissioning trust funds consist of equity securities and fixed income instruments and are carried at market value. The Company faces interest rate risk on the fixed income instruments, which consist primarily of municipal, federal and corporate bonds and which were valued at $57.3 million and $32.8 million as of December 31, 2004 and 2003, respectively. A hypothetical 10% increase in interest rates would reduce the fair values of these funds by $0.8 million and $0.5 million based on their fair values at December 31, 2004 and 2003, respectively.
Equity Price Risk
The Company’s decommissioning trust funds include marketable equity securities of approximately $32.1 million and $47.7 million at December 31, 2004 and 2003, respectively. A hypothetical 20% decrease in equity prices would reduce the fair values of these funds by $6.4 million and $9.5 million based on their fair values at December 31, 2004 and 2003, respectively.
Commodity Price Risk
The Company utilizes contracts of various durations for the purchase of natural gas, uranium concentrates and coal to effectively manage its available fuel portfolio. These agreements contain variable pricing provisions and are settled by physical delivery. The fuel contracts with variable pricing provisions, as well as substantially all of the Company’s purchased power requirements, are exposed to fluctuations in prices due to unpredictable factors, including weather and various other worldwide
Index to Financial Statements
events, which impact supply and demand. However, the Company’s exposure to fuel and purchased power price risk is substantially mitigated through the operation of the Texas and New Mexico Commission rules and the Company’s fuel clauses, as discussed previously.
In the normal course of business, the Company utilizes contracts of various durations for the forward sales and purchases of electricity to effectively manage its available generating capacity and supply needs. Such contracts include forward contracts for the sale of generating capacity and energy during periods when the Company’s available power resources are expected to exceed the requirements of its native load and sales for resale. They also include forward contracts for the purchase of wholesale capacity and energy during periods when the market price of electricity is below the Company’s expected incremental power production costs or to supplement the Company’s generating capacity when demand is anticipated to exceed such capacity. As of February 28, 2005, the Company had entered into forward sales and purchase contracts for energy as discussed in Part I, Item 1, “Business - Energy Sources - Purchased Power” and “Regulation - Power Sales Contracts.” These agreements are generally fixed-priced contracts which qualify for the “normal purchases and normal sales” exception provided in SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” and SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities,” including any effective implementation guidance discussed by the FASB Derivatives Implementation Group and are not recorded at their fair value in the Company’s financial statements. Because of the operation of the Texas and New Mexico Commission rules and the Company’s fuel clauses, these contracts do not expose the Company to significant commodity price risk.
Index to Financial Statements Management Report on Internal Control Over Financial Reporting
The Company’s management is responsible for establishing and maintaining adequate internal control over financial reporting. Internal control over financial reporting is defined in Rule 13a-15(f) or 15d-15(f) promulgated under the Securities Exchange Act of 1934 as a process designed by, or under the supervision of, the Company’s principal executive and principal financial officers and effected by the Company’s board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles and includes those policies and procedures that:
•
Pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the assets of the Company;
•
Provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and the receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and
•
Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
The Company’s management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004. In making this assessment, the Company’s management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) in Internal Control-Integrated Framework.
Based on its assessment, management believes that, as of December 31, 2004, the Company’s internal control over financial reporting is effective based on those criteria.
The Company’s independent registered public accounting firm, KPMG LLP, has issued an audit report on management’s assessment of the Company’s internal control over financial reporting. This report appears on page 47 of this report.
Index to Financial Statements
It em 8. Financial Statements and Supplementary Data
Index to Financial Statements
Report of Independent Registered Public Accounting Firm
The Board of Directors and Shareholders
El Paso Electric Company:
We have audited the accompanying consolidated balance sheets of El Paso Electric Company and subsidiary as of December 31, 2004 and 2003, and the related consolidated statements of operations, comprehensive operations, changes in common stock equity, and cash flows for each of the years in the three-year period ended December 31, 2004. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of El Paso Electric Company and subsidiary as of December 31, 2004 and 2003, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2004, in conformity with U.S. generally accepted accounting principles.
As discussed in Note D to the consolidated financial statements, the Company changed its method of accounting for asset retirement obligations in 2003.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of El Paso Electric Company’s internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 11, 2005 expressed an unqualified opinion on management’s assessment of, and the effective operation of, internal control over financial reporting.
KPMG LLP
El Paso, Texas
March 11, 2005
Index to Financial Statements Report of Independent Registered Public Accounting Firm
The Board of Directors and Shareholders
El Paso Electric Company:
We have audited management’s assessment, included in the accompanying Management Report on Internal Control Over Financial Reporting appearing on page 44, that El Paso Electric Company maintained effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commissions (COSO). El Paso Electric Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, management’s assessment that El Paso Electric Company maintained effective internal control over financial reporting as of December 31, 2004, is fairly stated, in all material respects, based on criteria established in Internal Control-Integrated Framework issued by COSO. Also, in our opinion, El Paso Electric Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control-Integrated Framework issued by COSO.
Index to Financial Statements We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of El Paso Electric Company and subsidiary as of December 31, 2004 and 2003, and the related consolidated statements of operations, comprehensive operations, changes in common stock equity, and cash flows for each of the years in the three-year period ended December 31, 2004, and our report dated March 11, 2005 expressed an unqualified opinion on those consolidated financial statements.
KPMG LLP
El Paso, Texas
March 11, 2005
Index to Financial Statements
EL PASO ELECTRIC COMPANY AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
See accompanying notes to consolidated financial statements.
Index to Financial Statements EL PASO ELECTRIC COMPANY AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS (Continued)
See accompanying notes to consolidated financial statements.
Index to Financial Statements
EL PASO ELECTRIC COMPANY AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands except for share data)
See accompanying notes to consolidated financial statements.
Index to Financial Statements
EL PASO ELECTRIC COMPANY AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF COMPREHENSIVE OPERATIONS
(In thousands)
See accompanying notes to consolidated financial statements.
Index to Financial Statements
EL PASO ELECTRIC COMPANY AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCK EQUITY
(In thousands except for share data)
See accompanying notes to consolidated financial statements.
Index to Financial Statements
EL PASO ELECTRIC COMPANY AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
See accompanying notes to consolidated financial statements.
Index to Financial Statements
EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
A. Summary of Significant Accounting Policies
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. El Paso Electric Company also serves wholesale customers in Texas and periodically in the Republic of Mexico.
Principles of Consolidation. The consolidated financial statements include the accounts of El Paso Electric Company and its wholly-owned subsidiary, MiraSol Energy Services, Inc. (“MiraSol”) (collectively, the “Company”). MiraSol, which began operations as a separate subsidiary in March 2001, provided energy efficiency products and services previously provided by the Company’s Energy Services Business Group. On July 19, 2002, all sales activities of MiraSol ceased. MiraSol remains a going concern in order to satisfy current contracts and warranty and service obligations on previously installed projects. See Note I. All intercompany transactions and balances have been eliminated in consolidation.
Use of Estimates. The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Basis of Presentation. The Company maintains its accounts in accordance with the Uniform System of Accounts prescribed by the Federal Energy Regulatory Commission (the “FERC”).
Re-application of SFAS No. 71 to New Mexico Jurisdiction. Regulated electric utilities typically prepare their financial statements in accordance with SFAS No. 71, “Accounting For the Effects of Certain Types of Regulation.” 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
Index to Financial Statements EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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.
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.
Comprehensive Income. Certain gains and losses that are not recognized currently in the consolidated statements of operations are reported as other comprehensive income in accordance with SFAS No. 130, “Reporting Comprehensive Income.”
Utility Plant. Depreciation is provided on a straight-line basis over the estimated remaining lives of the assets (ranging from 5 to 31 years), except for approximately $298 million of reorganization value allocated primarily to net transmission, distribution and general plant in service. This amount is being depreciated on a straight-line basis over the ten-year period of the Texas Rate Stipulation, which ends August 2005. For all other utility plant, Texas and New Mexico depreciation lives are the same.
In conjunction with a certain regulatory filing in the New Mexico jurisdiction, the Company implemented new depreciation rates effective January 1, 2004. The new rates had the effect of increasing depreciation and amortization expense by approximately $1.9 million and decreasing net income, after tax, by approximately $1.2 million or $.03 basic and diluted earnings per share.
The Company charges the cost of repairs and minor replacements to the appropriate operating expense accounts and capitalizes the cost of renewals and betterments. Gains or losses resulting from
Index to Financial Statements EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
retirements or other dispositions of operating property in the normal course of business are credited or charged to the accumulated provision for depreciation.
The cost of nuclear fuel is amortized to fuel expense on a units-of-production basis. A provision for spent fuel disposal costs is charged to expense based on requirements of the Department of Energy (the “DOE”) for disposal cost of approximately one-tenth of one cent on each kWh generated. The Company is also amortizing its share of costs associated with on-site spent fuel storage casks at Palo Verde over the burn period of the fuel that will necessitate the use of the storage casks. See Note C.
Impairment of Long-Lived Assets. In accordance with SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” long-lived assets, such as property, plant, and equipment and purchased intangibles subject to amortization, are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to estimated undiscounted future cash flows expected to be generated by the asset. If the carrying amount of an asset exceeds its estimated undiscounted future cash flows, an impairment charge is recognized for the amount by which the carrying amount of the asset exceeds the fair value of the asset.
Capitalized Interest. The Company capitalizes interest cost to construction work in progress and nuclear fuel in process in accordance with SFAS No. 34, “Capitalization of Interest Cost” for its Texas jurisdictional operations. For its New Mexico jurisdictional operations, the Company capitalizes interest and common equity costs to construction work in progress and nuclear fuel in process in accordance with SFAS No. 71. The amount of the equity component of the AFUDC capitalized to construction work in progress was $0.3 million for the year ended December 31, 2004.
Asset Retirement Obligation. Effective January 1, 2003, the Company adopted SFAS No. 143, “Accounting for Asset Retirement Obligations.” SFAS No. 143 sets forth accounting requirements for the recognition and measurement of liabilities associated with the retirement of tangible long-lived assets. An asset retirement obligation (“ARO”) associated with long-lived assets included within the scope of SFAS No. 143 is that for which a legal obligation exists under enacted laws, statutes, written or oral contracts, including obligations arising under the doctrine of promissory estoppel. Under the statement, these liabilities are recognized as incurred if a reasonable estimate of fair value can be established and are capitalized as part of the cost of the related tangible long-lived assets. In January 2003 the Company began recording the increase in the ARO due to the passage of time as an operating expense (accretion expense). See Note D.
Cash and Cash Equivalents. All temporary cash investments with an original maturity of three months or less are considered cash equivalents.
Index to Financial Statements EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Investments. The Company’s marketable securities, included in decommissioning trust funds in the balance sheets, are reported at fair market value and consist primarily of equity securities and municipal, federal and corporate bonds in trust funds established for decommissioning of its interest in Palo Verde. Such marketable securities are classified as “available-for-sale” securities and, as such, unrealized gains and losses are included in accumulated other comprehensive income as a separate component of common stock equity. However, if declines in fair value of marketable securities below original cost basis are determined to be other than temporary, then the declines are reported as losses in the consolidated statement of operations and a new cost basis is established for the affected securities at fair value. See Note M.
Inventories. Inventories, primarily parts, materials, supplies and fuel oil are stated at average cost not to exceed recoverable cost.
Operating Revenues Net of Energy Expenses. The Company accrues revenues for services rendered, including unbilled electric service revenues. Energy expenses are stated at actual cost incurred. The Company’s Texas retail customers are presently being billed under a fixed fuel factor approved by the Texas Commission. As of June 2003, the Company’s New Mexico retail customers are being billed under a fuel adjustment clause which is adjusted monthly, as approved by the New Mexico Commission in June 2004. The Company’s recovery of energy expenses in these jurisdictions is subject to periodic reconciliations of actual energy expenses incurred to actual fuel revenues collected. The difference between energy expenses incurred and fuel revenues charged to the Company’s Texas and New Mexico customers, as determined under Texas and New Mexico Commission rules, is reflected as net over/undercollection of fuel revenues in the consolidated balance sheets. See Note B.
Unbilled Revenues. Accounts receivable include accrued unbilled revenues of $18.0 million and $16.5 million at December 31, 2004 and 2003, respectively.
Allowance for Doubtful Accounts. Additions, deductions and balances for allowance for doubtful accounts for 2004, 2003 and 2002 are as follows (in thousands):
Index to Financial Statements EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Income Taxes. The Company accounts for federal and state income taxes under the asset and liability method of accounting for income taxes. Under this method, deferred income taxes are recognized for the estimated future tax consequences of “temporary differences” by applying enacted statutory tax rates for each taxable jurisdiction applicable to future years to differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities. The Company records a valuation allowance to reduce its deferred tax assets to the extent it is more likely than not that such deferred tax assets will not be realized. The effect on deferred tax assets and liabilities of a change in tax rate is recognized in income in the period that includes the enactment date.
Earnings per Share. Basic earnings per share is computed by dividing net income by the weighted average number of shares outstanding. Diluted earnings per share is computed by dividing net income by the weighted average number of shares and the dilutive impact of the sum of unvested restricted stock and the stock options that were outstanding during the period with the amount of outstanding options calculated by using the treasury stock method.
Stock Options and Restricted Stock. The Company has two stock-based long-term incentive plans and accounts for them under the recognition and measurement principles of APB Opinion No. 25, “Accounting for Stock Issued to Employees,” and related interpretations. Stock options have typically been granted with an exercise price equal to fair market value on the date of grant and, accordingly, no compensation expense is recorded by the Company. Restricted stock has been granted at fair market value. Accordingly, the Company recognizes compensation expense by ratably amortizing the fair market value of the restricted stock determined at the date of grant over the restriction period of the grant. If compensation expense for the option portion of the plans had been determined based on the fair value of the option at the grant date and amortized on a straight-line basis over the vesting period, consistent with the provisions of SFAS No. 123, “Accounting for Stock-Based Compensation,” the Company’s net earnings and earnings per share would have been reduced to the pro forma amounts presented below:
Index to Financial Statements EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The fair value for these options was estimated at the grant date using the Black-Scholes option pricing model. Weighted average assumptions and grant-date fair value for 2004, 2003 and 2002 are presented below:
Restricted Stock. Restricted stock has been granted at fair market value. Compensation expense for the restricted stock awards is recognized on a fair value basis and is measured by referencing the quoted market price of the shares at the grant date, amortized ratably over the restriction period. Unearned compensation related to restricted stock awards is a reduction of common stock equity and included in deferred and unearned compensation on the Company’s consolidated balance sheets.
Performance Shares. Subject to meeting certain performance criteria, performance shares will be granted to certain officers under the Company’s existing long-term incentive plan on January 1, 2006 and 2007. The Company currently recognizes the related compensation expense by ratably amortizing the current fair market value of awards that would be granted based on the current performance of the Company over the performance cycles. Consistent with the provisions of APB Opinion No. 25, compensation expense for performance shares will be adjusted for subsequent changes (such as the number of shares to be granted, if any, and the fair market value of the Company’s stock) in the expected outcome of the performance-related conditions until the end of the performance cycle. Any such adjustments are accounted for as a change in estimate, and the cumulative effect of the change on current and prior periods is recognized in the period of the change.
Other New Accounting Standards. At January 1, 2004, the Company adopted FASB Interpretation No. 46 (“FIN 46R”), “Consolidation of Variable Interest Entities,” which addresses how a business enterprise should evaluate whether it has a controlling financial interest in an entity through means other than voting rights and accordingly should consolidate the entity. As of December 31, 2004, the Company has had no transactions that have established a variable interest entity and the implementation of this standard did not have an impact on the Company’s financial position or results of operations.
SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity,” was issued in May 2003. This statement established standards for the classification and measurement of certain financial instruments with characteristics of both liabilities and equity. The statement also included required disclosures for financial instruments within its scope. For the Company, the statement was effective as of January 1, 2004. The Company currently does not have
Index to Financial Statements EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
any financial instruments that are within the scope of this statement and the implementation of this standard did not have an impact on the Company’s financial statements.
In November 2004, the FASB issued SFAS No. 151, “Inventory Costs” - an amendment of Accounting Research Bulletin No. 43 (“ARB No. 43”), (“Inventory Pricing”). ARB No. 43 previously stated that “under some circumstances, items such as idle facility expense, excessive spoilage, double freight and rehandling costs may be so abnormal as to require treatment as current period charges.” SFAS No. 151 requires that those items be recognized as current-period charges regardless of whether they meet the criterion of “so abnormal.” The provisions of this statement are effective for inventory costs incurred during fiscal years beginning after June 15, 2005. The Company does not believe SFAS No. 151 will have a significant impact on the Company’s consolidated financial statements.
In December 2004, the FASB issued SFAS No. 153, “Exchanges of Nonmonetary Assets” - an amendment of Accounting Principles Board Opinion No. 29 (“APB No. 29”), “Accounting for Nonmonetary Transactions.” The guidance in APB No. 29 is based on the principle that exchanges of nonmonetary assets should be measured based on the fair value of the assets exchanged, with certain exceptions. SFAS No. 153 amends the opinion to eliminate the exception for nonmonetary exchanges of similar productive assets and replaces it with a general exception for exchanges of nonmonetary assets that do not have “commercial substance.” A nonmonetary exchange has “commercial substance” if the future cash flows of the entity are expected to change significantly as a result of the exchange. The provisions of this statement are effective for fiscal periods beginning after June 15, 2005. The Company does not believe SFAS No. 153 will have a significant impact on the Company’s consolidated financial statements.
In December 2004, the FASB issued a revision of SFAS No. 123, “Accounting for Stock-Based Compensation.” SFAS No. 123 (revised) focuses primarily on accounting for transactions in which an entity obtains employee services in share-based payment transactions. SFAS No. 123 (revised) requires a public entity to measure the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award (with some limited exceptions). That cost will be recognized over the period during which an employee is required to provide service in exchange for the award - “the requisite service period” - typically the vesting period. No compensation cost is recognized for equity instruments for which employees do not render the requisite service. SFAS No. 123 (revised) is effective for public entities that do not file as small business issuers as of the beginning of the first interim or annual reporting period that begins after June 15, 2005. SFAS No. 123 (revised) applies to all awards granted after the required effective date and to awards modified, repurchased or cancelled after that date. Additionally, compensation cost for outstanding awards for which the requisite service has not been rendered as of the effective date shall be expensed as the requisite service is rendered on or after the required effective date. The compensation cost for that portion of awards shall be based on the grant-date fair value of those awards as calculated for pro forma disclosure under SFAS No. 123. Due to timing of the release of SFAS No. 123 (revised), the Company has not yet completed the analysis of the ultimate impact that this new pronouncement will have on the
Index to Financial Statements EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Company’s financial statements but does not expect this statement to have an effect materially different than the pro forma disclosures provided in Note A.
Reclassification. Certain amounts in the consolidated financial statements for 2003 and 2002 have been reclassified to conform with the 2004 presentation.
B. 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
Index to Financial Statements EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 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
Index to Financial Statements EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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.
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.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 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.
Index to Financial Statements EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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.
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.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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.
Index to Financial Statements EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
C. Utility Plant, Palo Verde and Other Jointly-Owned Utility Plant
The table below presents the balance of each major class of depreciable assets at December 31, 2004 (in thousands):
Amortization of intangible plant (software) is provided on a straight-line basis over the estimated useful life of the asset (ranging from 3 to 10 years). The amortization expense for intangible plant in 2004 was $0.9 million. The table below presents the estimated amortization expense for the next five years (in thousands):
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: Arizona Public Service Company (“APS”), Southern California Edison Company (“SCE”), Public Service Company of New Mexico (“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 operation of Palo Verde and the relationship among the Palo Verde Participants is governed by the Arizona Nuclear Power Project Participation Agreement (the “ANPP Participation Agreement”).
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 Company’s share of direct expenses in Palo Verde and other jointly-owned utility plants is reflected
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in fuel expense, other operations expense, maintenance expense, miscellaneous other deductions, and taxes other than income taxes in the Company’s consolidated statements of operations. 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. Because it is impracticable to predict defaulting participants, the Company cannot estimate the maximum potential amount of future payment, if any, which could be required under this provision.
Other jointly-owned utility plant includes a 7% interest in Units 4 and 5 at Four Corners Generating Station (“Four Corners”) and certain other transmission facilities. A summary of the Company’s investment in jointly-owned utility plant, excluding fuel, at December 31, 2004 and 2003 is as follows (in thousands):
Palo Verde
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.
The Company has established external trust with independent trustees, which enable the Company to record a current deduction for federal income tax purposes of a portion of amounts funded. As of December 31, 2004 and 2003, the fair market value of the trust funds was approximately $89.4 million and $80.5 million, respectively, which is reflected in the Company’s consolidated balance sheets in deferred charges and other assets.
Index to Financial Statements EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 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
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waste generated by all domestic power reactors. In accordance with the Waste Act, the DOE entered into a spent nuclear fuel contract with the Company and all other Palo Verde Participants. The DOE has previously reported that its spent nuclear fuel disposal facilities would not be in operation until 2010. Subsequent judicial decisions required the DOE to start accepting spent nuclear fuel by January 31, 1998. The DOE did not meet that deadline, and the Company cannot currently predict when spent fuel shipments to the DOE’s permanent disposal site will commence.
The Company expects to incur significant on-site spent fuel storage costs during the life of Palo Verde that the Company believes are the responsibility of the DOE. These costs will be amortized over the burn period of the fuel that will necessitate the use of the alternative on-site storage facilities until an agreement is reached with the DOE for recovery of these costs. In December 2003, APS, in conjunction with other nuclear plant operators, filed suit against the DOE on behalf of the Palo Verde Participants to recover monetary damages associated with the delay in the DOE’s acceptance of spent fuel. The Company is unable to predict the outcome of these matters at this time.
Disposal of Low-Level Radioactive Waste. Congress has established requirements for the disposal by each state of low-level radioactive waste generated within its borders. Arizona, California, North Dakota and South Dakota have entered into a compact (the “Southwestern Compact”) for the disposal of low-level radioactive waste. California will act as the first host state of the Southwestern Compact, and Arizona will serve as the second host state. The construction and opening of the California low-level radioactive waste disposal site in Ward Valley has been delayed due to extensive public hearings, disputes over environmental issues and review of technical issues related to the 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
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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 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
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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.
D. Accounting for Asset Retirement Obligations
Effective January 1, 2003, the Company adopted SFAS No. 143, “Accounting for Asset Retirement Obligations.” The adoption of SFAS No. 143 primarily affected the accounting for the decommissioning of the Company’s Palo Verde and Four Corners Stations and changed the method used to report the decommissioning obligation. Upon emergence from bankruptcy in 1996, the Company was required under fresh-start reporting to adopt the concepts of an early exposure draft of the SFAS No. 143 project and accordingly, recognized the present value of its projected Palo Verde asset retirement costs as both a component of its capitalized cost of Palo Verde and as a decommissioning liability. Beginning in 1996 and through 2002, the Company recognized accretion of the Palo Verde ARO liability as a component of interest expense and depreciation of the Palo Verde asset retirement cost as depreciation expense in its consolidated financial statements. Upon adoption of SFAS No. 143, the net difference between the amounts determined under SFAS No. 143 and the Company’s previous method of accounting for such activities was recognized as a decrease in the ARO of $95.5 million, a decrease in net plant in service of $30.9 million, and a cumulative effect of accounting change of $39.6 million, net of related taxes of $25.0 million. The cumulative effect of accounting change is primarily due to two factors: (i) using a longer discount period (i.e., longer remaining life) as a result of assessing the probability of a license extension at Palo Verde and (ii) a change in the discount rate used. In January 2003, the Company began recording the increase in the ARO due to the passage of time as an operating expense (accretion expense). As the DOE assumes responsibility for the permanent disposal of spent fuel, spent fuel costs have not been included in the ARO calculation. The Company has six external trust funds with independent trustees which are legally restricted to settling its ARO at Palo Verde. The fair value of the fund at December 31, 2004 is $89.4 million.
A reconciliation of the Company’s ARO liability for Palo Verde and Four Corners Stations is as follows (in thousands):
Index to Financial Statements EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The Company has transmission and distribution lines which are operated under various property easement agreements. If the easements were to be released, the Company may have a legal obligation to remove the lines; however, the Company has assessed the likelihood of this occurring as remote. The majority of these easements include renewal options which the Company routinely exercises. Additionally, the Company has certain components of its local generating stations which may result in an ARO. However, substantial uncertainty exists surrounding the ultimate removal date for these facilities. Due to the nature of these assets and the uncertainty of final removal timing and costs, an ARO has not been included for these assets as the ARO cannot be reasonably estimated at this time.
Amounts recorded under SFAS No. 143 are subject to various assumptions and determinations such as (i) whether a legal obligation exists to remove assets; (ii) estimation of the fair value of the costs of removal; (iii) when final removal will occur; (iv) future changes in decommissioning cost escalation rates; and (v) the credit-adjusted interest rates to be utilized in discounting future liabilities. Changes that may arise over time with regard to these assumptions and determinations will change amounts recorded in the future as an expense for AROs. If the Company incurs or assumes any liability in retiring any asset at the end of its useful life without a legal obligation to do so, it will record such retirement costs as incurred.
The Company’s most recent Palo Verde decommissioning study, completed in 2001, estimated that the Company’s share of Palo Verde decommissioning costs would be approximately $311.6 million, in year 2001 dollars. This estimated liability differs from the ARO liability of $60.4 million recorded by the Company as of December 31, 2004. This difference can be attributed to how SFAS No. 143 measures the ARO liability, relative to current cost estimates, and the inherent assumption in SFAS No. 143 that Palo Verde will operate until the end of its useful life (which includes an assessment of the probability of a license extension). The ARO liability calculation begins with the same current cost estimate referenced above, then escalates that cost over the remaining life of the plant, finally discounting the resulting cost at a credit-risk adjusted discount rate. Since the Company assumed an escalation rate of 3.6% and a credit-risk adjusted discount rate of 9.5% in its calculation of the ARO liability, the ARO liability is significantly less than the Company’s share of the current estimated cost to decommission Palo Verde in 2001 dollars. As Palo Verde approaches the end of its estimated useful life, the difference between the ARO liability and future current cost estimates will narrow over time due to the accretion of the ARO liability.
E. Common Stock
Overview
The Company’s common stock has a stated value of $1 per share, with no cumulative voting rights or preemptive rights. Holders of the common stock have the right to elect the Company’s directors and to vote on other matters.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Long-Term Incentive Plans
The Company shareholders have approved the adoption of two stock-based long-term incentive plans. The first plan was approved in 1996 (the “1996 Plan”) and authorized the issuance of up to 3.5 million shares of common stock for the benefit of officers, key employees and directors. The second plan was approved in 1999 (the “1999 Plan”) and authorized the issuance of up to two million shares of common stock for the benefits of directors, officers, managers, other employees and consultants. The common stock may be issued through the award or grant of non-statutory stock options, incentive stock options, stock appreciation rights, restricted stock, bonus stock and performance stock.
Stock Options. Stock options have been granted at exercise prices equal to or greater than the market value of the underlying shares at the date of grant. The options expire ten years from the date of grant unless terminated earlier by the Board of Directors. The following table summarizes the transactions of the Company’s stock options for 2004, 2003 and 2002:
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Stock option awards provide for vesting periods of up to six years. Stock options outstanding and exercisable at December 31, 2004 are set forth in the following table:
The number of stock options exercisable and the weighted average exercise price of these stock options are as follows:
Restricted Stock. The Company has awarded vested and unvested restricted stock awards under the 1996 and 1999 Plans. Restrictions from resale generally lapse, and unvested awards vest, over periods of three to five years. The market value of vested restricted stock awards is expensed at the time of grant. The market value of the unvested restricted stock at the date of grant is recorded as deferred and unearned compensation and is shown as a separate component of common stock equity and is amortized to expense over the restriction period. During 2004, 2003 and 2002, approximately $1.2 million, $1.3 million and $1.9 million, respectively, related to restricted stock awards was charged to expense. The following table summarizes the vested and unvested restricted stock awards for 2004, 2003 and 2002:
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The weighted average market values at grant date for restricted stock awarded during 2004, 2003 and 2002 are $14.60, $11.47 and $14.52, respectively.
The holder of a restricted stock award has rights as a shareholder of the Company, including the right to vote and, if applicable, receive cash dividends on restricted stock, except that certain restricted stock awards require any cash dividend on restricted stock to be delivered to the Company in exchange for additional shares of restricted stock of equivalent market value.
Performance Shares. On January 1, 2006 and 2007, subject to meeting certain performance criteria, performance shares will be granted to certain officers under the Company’s existing long-term incentive plan. The Company currently recognizes the related compensation expense by ratably amortizing the current fair market value of awards that would be granted based on the current performance of the Company over the performance cycles. Consistent with the provisions of APB Opinion No. 25, compensation expense for performance shares will be adjusted for subsequent changes (such as the number of shares to be granted, if any, and the fair market value of the Company’s stock) in the expected outcome of the performance-related conditions until the end of the performance cycle. Any such adjustments are accounted for as a change in estimate, and the cumulative effect of the change on current and prior periods is recognized in the period of the change. The actual number of shares granted can range from zero to 198,000 shares. During 2004, $1.6 million related to performance stock awards was charged to expense.
Common Stock Repurchase Program
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, pursuant to the two million share buyback program authorized by its Board of Directors in February 2004. 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 currently authorized 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.
Index to Financial Statements EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Reconciliation of Basic and Diluted Earnings Per Share
The reconciliation of basic and diluted earnings per share before extraordinary item and cumulative effect of accounting change is presented below:
Index to Financial Statements EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Options excluded from the computation of diluted earnings per share because the exercise price was greater than the average market price for the periods presented are as follows:
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
F. Accumulated Other Comprehensive Income (Loss)
Accumulated other comprehensive income (loss) consists of the following components (in thousands):
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
G. Long-Term Debt and Financing Obligations
Outstanding long-term debt and financing obligations are as follows:
(1) First Mortgage Bonds
Substantially all of the Company’s utility plant is subject to liens under the First Mortgage Indenture. The First Mortgage Indenture imposes certain limitations on the ability of the Company to (i) declare or pay dividends on common stock; (ii) incur additional indebtedness or liens on mortgaged property and (iii) enter into a consolidation, merger or sale of assets.
The Series D bonds may not be redeemed by the Company prior to maturity. The Series E bonds may be redeemed at the option of the Company, in whole or in part, at 104.70% of par value beginning February 1, 2006, 102.35% of par value beginning February 1, 2007, and at par value beginning February 1, 2008. The Company is not required to make mandatory redemption or sinking fund payments with respect to the bonds prior to maturity.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Repurchases, excluding repayment upon maturity, of First Mortgage Bonds made during 2004, 2003 and 2002 are as follows (in thousands):
Internally generated funds were used for the above repurchases. Losses of $5.4 million and $3.4 million were recorded in 2004 and 2002, respectively, relating to these repurchases and include premiums paid and unamortized issuance costs.
(2) Pollution Control Bonds
The Company has four series of tax exempt Pollution Control Bonds in an aggregate principal amount of approximately $193.1 million. Upon the occurrence of certain events, which includes the remarketing of the bonds, the bonds may be required to be repurchased at the holder’s option or are subject to mandatory redemption. All of the pollution control bonds are classified as current maturities at December 31, 2004 since they are within one year of being remarketed. The interest rates will remain at their current fixed interest rates until remarketing in August 2005.
(3) Promissory Note
The note has an annual interest rate of 5.5%, is secured by certain furniture and fixtures and is due in 2005.
(4) Nuclear Fuel Financing
The Company has available a $100 million credit facility that was renewed for a five-year term in December 2004. The credit facility provides for up to $70 million for the financing of nuclear fuel, which is accomplished through a trust that borrows under the facility to acquire and process the nuclear fuel. The Company is obligated to repay the trust’s borrowings with interest and has secured this obligation with Collateral Series First Mortgage Bonds. In the Company’s financial statements, the assets and liabilities of the trust are reported as assets and liabilities of the Company. Any amounts not borrowed by the trust may be borrowed by the Company for working capital needs.
The $100 million credit facility requires compliance with certain total debt and interest coverage ratios. The Company was in compliance with these requirements throughout 2004. No amounts are currently outstanding on this facility for working capital needs.
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As of December 31, 2004, the scheduled maturities for the next five years of long-term debt and financing obligations are as follows (in thousands):
The table above does not reflect future obligations and maturities related to nuclear fuel purchase commitments.
H. Income Taxes
The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and liabilities at December 31, 2004 and 2003 are presented below (in thousands):
The deferred tax asset valuation allowance increased by approximately $0.6 million in 2004, and decreased $0.8 million and $6.8 million in 2003 and 2002, respectively. The 2004 valuation allowance increase of $0.6 million consists of a revaluation of investment tax credits as a result of the IRS settlement. The 2003 valuation allowance decrease of $0.8 million consists of (i) a $0.3 million
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adjustment to capital in excess of stated value in accordance with Statement of Position (“SOP”) 90-7, “Financial Reporting by Entities in Reorganization Under Bankruptcy Code” to recognize a tax benefit for valuation allowance that was not used as a result of investment tax credits that were utilized in 2003 and (ii) a $0.5 million writedown related to expired investment tax credits of $0.8 million less deferred tax benefits of $0.3 million. The 2002 valuation allowance decrease of $6.8 million consists of (i) a $4.5 million writedown related to expired investment tax credit of $6.9 million less deferred tax benefits of $2.4 million and (ii) a $2.3 million adjustment to capital in excess of stated value in accordance to SOP 90-7 to recognize a tax benefit for valuation allowance that was not used as a result of investment tax credits that were utilized in 2002.
Based on the average annual book income before taxes for the prior three years and future projected annual book income, excluding the effects of extraordinary and unusual or infrequent items, the Company believes that the net deferred tax assets will be fully realized at current levels of book and taxable income. The Company’s valuation allowance of $2.9 million at December 31, 2004, if subsequently recognized as a tax benefit, would be credited directly to capital in excess of stated value in accordance with SOP 90-7.
The Company recognized income taxes as follows (in thousands):
The current federal income tax expense for 2004, 2003 and 2002 results primarily from the accrual of alternative minimum tax (“AMT”). The significant increase in 2004 from 2003 primarily
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relates to the IRS settlement. Deferred federal income tax includes an offsetting AMT benefit of $18.9 million, $2.1 million and $13.0 million for 2004, 2003 and 2002, respectively. The state income tax benefit for 2004 results primarily from the state effects of the re-application of SFAS No. 71 to the Company’s New Mexico jurisdictional operations and the IRS settlement.
Federal income tax provisions differ from amounts computed by applying the statutory rate of 35% to book income before federal income tax as follows (in thousands):
The effective income tax rate without IRS settlement excludes the tax benefit associated with the reduction in estimated contingent tax liability of $3.5 million and state taxes net of federal benefit of $2.7 million. See Note I.
As of December 31, 2004, the Company had $0.5 million of federal tax NOL carryforwards, $1.4 million of capital loss carryforwards, $5.6 million of investment tax credit (“ITC”) carryforwards including $0.2 million of wind energy tax credit, and $51.5 million of AMT credit carryforwards. If unused, the NOL carryforwards would expire at the end of 2011, the capital loss carryforwards would expire in 2007 through 2008, the ITC carryforwards would expire in 2005, the wind energy credit carryforwards would expire in 2016 through 2019, and the AMT credit carryforwards have an unlimited life.
Index to Financial Statements EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
I. Commitments, Contingencies and Uncertainties
Power Contracts
As of December 31, 2004, the Company had entered into the following significant agreements with various counterparties for forward firm purchases and sales of electricity:
The Company also has an agreement with a counterparty for power exchanges under which the Company will receive 30 MW of on-peak capacity and associated energy through 2005 at the Eddy County tie and concurrently deliver the same amount at Palo Verde and/or Four Corners. 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.
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.
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The Company incurred the following expenditures to comply with federal environmental statutes (in thousands):
(1) Includes $0.6 million and $1.6 million in remediation costs for the years ended December 31, 2004 and 2002, respectively.
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 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.
Tax Matters
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
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income for 2004 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.
MiraSol Warranty Obligations
MiraSol is an energy services subsidiary which offered a variety of services to reduce energy use and/or lower energy costs. MiraSol was not a power marketer. On July 19, 2002, all sales activities of MiraSol ceased. MiraSol remains a going concern in order to satisfy current contracts and warranty and service obligations on previously installed projects. Management of MiraSol continues to assess projects for potential warranty obligations. As part of the assessment, several discussions have been held with a large customer on a $5.6 million generator project. Two warranty issues associated with the project have been identified, and management has contracted with a third party to address the warranty claims. As of December 31, 2004, the Company has a reserve for those warranty claims in the amount of $1.3 million. Accruals, charges and balances for the reserve for warranty claims are as follows:
While no other probable warranty liabilities have been identified at this time, if it is determined at a future date that MiraSol has further obligations to this customer or any other customer, and contributions from MiraSol, its subcontractors or any other third party are insufficient to honor the warranty obligations, the Company intends to honor any such warranty obligations after making appropriate regulatory filings, if any.
Customer Information System
During 2003, the Company completed an assessment of the Customer Information System (“CIS”) project and of alternatives to completion of the project. This assessment included analyzing the impact that potential delays in the implementation of deregulation and resulting changes in billing requirements, and the software’s ability to perform to specification. Based on this assessment and on events related to the project which occurred, the Company abandoned the CIS project and recognized an asset impairment loss of approximately $17.6 million. The Company is now analyzing various options to meet its current and projected CIS needs.
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Lease Agreements
The Company has operating leases for administrative offices and certain warehouse facilities. The administrative offices lease has a 10-year term ending May 31, 2007. The minimum lease payments are $1.0 million annually and are adjusted each year by 50% of the percentage change of the Consumer Price Index. The warehouse facilities lease expires in January 2006 and has two concurrent renewal options of six months each. The lease payments are $0.3 million annually. The lease agreements do not impose any restrictions relating to issuance of additional debt, payment of dividends or entering into other lease arrangements. The Company has no significant capital lease agreements.
The Company’s total annual rental expense related to operating leases was $1.2 million for 2004 and $1.9 million for 2003 and 2002. As of December 31, 2004, the Company’s minimum future rental payments for the next five years are as follows (in thousands):
Union Matters
In 2003, a majority of employees in the Company’s meter reading and collections areas and facilities services area, comprised of 75 employees, voted in favor of representation by the International Brotherhood of Electrical Workers, Local 960 (“Local 960”). In 2004, a majority of employees in the customer service area, comprised of 63 employees, voted in favor of representation by Local 960. The Company has begun collective bargaining negotiations with Local 960 on behalf of these employees.
J. Litigation
The Company is a party to various legal actions. In many of these matters, the Company has excess casualty liability insurance that covers the various claims, actions and complaints. Based upon a review of these claims and applicable insurance coverage, the Company believes that, except as described below, none of these claims will have a material adverse effect on the financial position, results of operations and cash flows of the Company. The Company expenses legal costs, including expenses related to loss contingencies, as they are incurred.
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
Index to Financial Statements EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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.
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
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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 an 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 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.
K. Employee Benefits
Retirement Plans
The Company’s Retirement Income Plan (the “Retirement Plan”) covers employees who have completed one year of service with the Company and work at least a minimum number of hours each year. The Retirement Plan is a qualified noncontributory defined benefit plan. Upon retirement or death of a vested plan participant, assets of the Retirement Plan are used to pay benefit obligations under the
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Retirement Plan. Contributions from the Company are at least the minimum funding amounts required by the IRS under provisions of the Retirement Plan, as actuarially calculated. The assets of the Retirement Plan are invested in equity securities, debt securities and cash equivalents and are managed by professional investment managers appointed by the Company.
The Company’s non-qualified retirement income plan for 2003 and 2002 is a non-funded defined benefit plan which covers certain former employees of the Company. During 2004, the Company adopted a new non-qualified retirement income plan to cover certain active employees of the Company. The benefit cost for the non-qualified retirement income plans are based on substantially the same actuarial methods and economic assumptions as those used for the Retirement Plan.
The Company uses a measurement date of December 31 for its retirement plans. The Company accounts for the Retirement Plan and the non-qualified retirement income plans under SFAS No. 87, “Employers’ Accounting for Pensions.” In 2003, the Company adopted SFAS No. 132 (revised 2003), “Employers’ Disclosure about Pensions and Other Postretirement Benefits,” (“SFAS No. 132 revised”) which expands the original disclosure requirements of SFAS No. 132.
The obligations and funded status of the plans are presented below (in thousands):
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Amounts recognized in the Company’s consolidated balance sheets consist of the following (in thousands):
The accumulated benefit obligation for all retirement plans was $154.7 million and $140.6 million at December 31, 2004 and 2003, respectively.
The accumulated benefit obligation in excess of plan assets is as follows (in thousands):
The following are the weighted-average actuarial assumptions used to determine the benefit obligations:
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The components of net periodic benefit cost are presented below (in thousands):
The increase in minimum liability included in other comprehensive income is as follows (in thousands):
The following are the weighted-average actuarial assumptions used to determine the net periodic benefit cost at January 1, 2004:
The Company reassesses various actuarial assumptions at least on an annual basis. The discount rate is changed at each measurement date based on prevailing market interest rates inherent in high-
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
quality (AA and better) corporate bonds that would provide the future cash flow needed to pay the benefits included in the benefit obligation as they become due, as well as on publicly available bond indices. The Company changed its discount rate to determine the benefit obligations from 6.00% to 5.75% at December 31, 2004. For determining 2005 benefit costs, the 5.75% discount rate is not expected to change. A 1.0% decrease in the discount rate would increase the 2004 retirement plans’ projected benefit obligation by 16%. A 1.0% increase in the discount rate would decrease the 2004 retirement plans’ projected benefit obligation by 13%.
The Company’s overall expected long-term rate of return on assets is 8.50%, which is both a pre-tax and after-tax rate as pension funds are generally not subject to income tax. The expected long-term rate of return is based on the sum of the expected returns on individual asset categories with a target asset allocation of 65% equity and 35% debt securities. The expected returns for equity securities are based on historical risk premiums above the current fixed income rate, while the expected returns for the debt securities are based on the portfolio’s yield to maturity.
Given recent market conditions, the Company has emphasized capital preservation and therefore, the asset allocations at December 31, 2004 and 2003 do not reflect the targeted long-term asset allocation which remains unchanged. The Company’s Retirement Plan weighted-average asset allocations by asset category are as follows:
The Company’s investment goals for the Retirement Plan are to maximize returns subject to specific risk management policies. Its risk management policies permit investments in equity and debt securities, mutual funds and cash/cash equivalents and prohibit direct investments in fixed income derivatives, foreign debt securities, real estate or commingled funds, private placements and tax-exempt debt of state and local governments. The Company addresses diversification by the use of mutual fund investments whose underlying investments are in domestic and international equity securities and domestic fixed income securities. The liquidity of these funds is enhanced through the purchase of highly marketable securities.
The contributions for the Retirement Plan, as actuarially calculated, are based on the minimum funding amounts required by the IRS. The Company expects to contribute $18.5 million to its retirement plans in 2005, although the Company has no 2005 minimum funding requirements for the Retirement Plan.
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The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid (in thousands):
Other Postretirement Benefits
The Company provides certain health care benefits for retired employees and their eligible dependents and life insurance benefits for retired employees only. Substantially all of the Company’s employees may become eligible for those benefits if they retire while working for the Company. Those benefits are accounted for under SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions.” Contributions from the Company are based on the funding amounts required by the Texas Commission in the Texas Rate Stipulation. The assets of the plan are invested in equity securities, debt securities, and cash equivalents and are managed by professional investment managers appointed by the Company. The Company uses a measurement date of December 31 for its other postretirement benefits plan.
In December 2003, the Company elected to defer recognition of the potential effect of the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (the “Act”) until authoritative guidance on the accounting for the federal subsidy is issued. In May 2004, the FASB issued FASB Staff Position No. 106-2 “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003,” (“FSP 106-2”) which provided guidance on the accounting for the effects of the Act for employers that sponsor a single-employer defined benefit postretirement healthcare plan for which the employer has concluded that prescription drug benefits available under the plan are actuarially equivalent to the Medicare Part D benefit and the expected subsidy will offset or reduce the employer’s share of the cost of the benefit. The Company determined that the prescription drug benefit of its plan were actuarially equivalent to the Medicare Part D benefit. FSP 106-2 requires measurement of the accumulated postretirement benefit obligation and the net periodic postretirement benefit cost to reflect the effects of the subsidy. The effect of the Medicare Part D subsidy on the accumulated postretirement benefit obligation and net periodic benefit cost, is shown below (in thousands):
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The obligations and funded status of the plan are presented below (in thousands):
Amounts recognized in the Company’s consolidated balance sheets consist of accrued postretirement costs of $98.8 million and $94.5 million for 2004 and 2003, respectively. The discount rates used to determine the accrued postretirement cost were 5.75% and 6.00% at December 31, 2004
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and 2003, respectively. The rate of compensation increase was 5% for both December 31, 2004 and 2003.
The components of net periodic benefit cost are presented below (in thousands):
The following are the weighted-average actuarial assumptions used to determine the net periodic benefit cost:
The Company reassesses various actuarial assumptions at least on an annual basis. The discount rate is changed at each measurement date based on prevailing market interest rates inherent in high-quality (AA and better) corporate bonds that would provide the future cash flow needed to pay the benefits included in the benefit obligation as they become due, as well as on publicly available bond indices. At December 31, 2004, the Company changed its discount rate from 6.00% to 5.75% for the other postretirement benefits plan. For determining 2005 benefit cost, the 5.75% discount rate is not expected to change. A 1.0% decrease in the discount rate would increase the 2004 accumulated postretirement benefit obligation by 19%. A 1.0% increase in the discount rate would decrease the 2004 accumulated postretirement benefit obligation by 16%.
For measurement purposes, a 9.6% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2005; the rate was assumed to decrease gradually to 6% for 2008 and remain at that level thereafter. Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plan. The effect of a 1% change in these assumed health care cost
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trend rates would increase or decrease the benefit obligation by $18.1 million or $14.5 million, respectively. In addition, such a 1% change would increase or decrease the aggregate service and interest cost components of the net periodic benefit cost by $1.8 million or $1.4 million, respectively.
The Company’s overall expected long-term rate of return on assets, on an after-tax basis, is 5.90%. This return is based on the sum of the expected returns on individual asset categories with a target asset allocation of 60% equity and 40% debt securities. The expected returns for equity securities are based on historical risk premiums above the current fixed income rate, while the expected returns for the debt securities are based on the portfolio’s yield to maturity.
Given recent market conditions, the Company has emphasized capital preservation and therefore, the asset allocations at December 31, 2004 and 2003 do not reflect the targeted long-term asset allocation which remains unchanged. The Company’s other postretirement benefits plan weighted average asset allocations by asset category are as follows:
The Company’s investment goals for the postretirement benefits plan are to maximize returns subject to specific risk management policies. Its risk management policies permit investments in equity and debt securities, mutual funds and cash/cash equivalents and prohibit direct investments in fixed income derivatives, foreign debt securities, real estate or commingled funds and private placements. The Company’s investment policies and strategies for the postretirement benefits plan are based on target allocations for individual asset categories. The Company addresses diversification by the use of mutual fund investments whose underlying investments are in domestic and international equity securities and domestic fixed income securities. The liquidity of these funds is enhanced through the purchase of highly marketable securities.
The Company expects to contribute $3.4 million to its other postretirement benefits plan in 2005.
The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid (in thousands):
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401(k) Defined Contribution Plans
The Company sponsors 401(k) defined contribution plans covering substantially all employees. Historically, the Company has provided a 50 percent matching contribution up to 6 percent of the employee’s base salary subject to certain other limits. Total matching contributions made to the savings plans for the years 2004, 2003 and 2002 were $1.3 million, $1.3 million and $1.4 million, respectively.
Annual Short-Term Bonus Plan
The Annual Short-Term Bonus Plan (the “Bonus Plan”) provided for the payment of cash awards to eligible Company employees, including each of its named executive officers. Payment of awards was based on the achievement of performance measures reviewed and approved by the Company’s Board of Directors Compensation Committee. Generally, these performance measures were based on meeting certain financial, operational and individual performance criteria. For 2004, the financial performance goals were based on earnings per share and the operational performance goals were based on safety and customer satisfaction. If a certain level of earnings per share was not attained, no bonuses would have been paid under the Bonus Plan. The Company was able to attain the required levels of improvements in the earnings per share and the customer satisfaction goals which resulted in a 2004 bonus of $3.5 million. The Company was also able to attain the required levels of improvement in the safety performance measures for medium and high risk employees in 2004, 2003 and 2002, which resulted in safety bonuses of $0.9 million, $0.7 million and $1.0 million, respectively. The Company has renewed the Bonus Plan in 2005 with similar goals.
L. 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.
Index to Financial Statements EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 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.
M. Financial Instruments and Investments
SFAS No. 107, “Disclosure about Fair Value of Financial Instruments,” requires the Company to disclose estimated fair values for its financial instruments. The Company has determined that cash and temporary investments, accounts receivable, decommissioning trust funds, long-term debt and financing obligations, accounts payable and customer deposits meet the definition of financial instruments. The carrying amounts of cash and temporary investments, accounts receivable, accounts payable and customer deposits approximate fair value because of the short maturity of these items. Decommissioning trust funds are carried at market value.
Index to Financial Statements EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The fair values of the Company’s long-term debt and financing obligations, including the current portion thereof, are based on estimated market prices for similar issues and are presented below (in thousands):
(1) The interest rate on the Company’s financing for nuclear fuel purchases is reset every quarter to reflect current market rates. Consequently, the carrying value approximates fair value.
As of January 1, 2001, the Company adopted SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended by SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities,” including any effective implementation guidance discussed by the FASB Derivatives Implementation Group. This standard requires the recognition of derivatives as either assets or liabilities in the balance sheet with measurement of those instruments at fair value. Any changes in the fair value of these instruments are recorded in earnings or other comprehensive income.
The Company uses commodity contracts to manage its exposure to price and availability risks for fuel purchases and power sales and purchases and these contracts generally have the characteristics of derivatives. The Company does not trade or use these instruments with the objective of earning financial gains on the commodity price fluctuations. The Company has determined that all such contracts, except for certain natural gas commodity contracts with optionality features, that had the characteristics of derivatives met the “normal purchases and normal sales” exception provided in SFAS No. 133, and, as such, were not required to be accounted for as derivatives pursuant to SFAS No. 133 and other guidance.
The Company determined that certain of its natural gas commodity contracts with optionality features are not eligible for the normal purchases exception and, therefore, are required to be accounted for as derivative instruments pursuant to SFAS No. 133. However, as of December 31, 2004, the variable, market-based pricing provisions of existing gas contracts are such that these derivative instruments have no significant fair value.
Index to Financial Statements EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The fair value of the Company’s marketable securities at December 31, 2004 was $89.4 million. Gross unrealized losses on marketable securities and the fair value of the related securities, aggregated by investment category and length of time that individual securities have been in a continuous unrealized loss position, at December 31, 2004, were as follows:
The total impaired securities are comprised of approximately fifty investments that are in an unrealized loss position. The Company monitors the length of time the investment trades below its cost basis along with the amount and percentage of the unrealized loss in determining if a decline in fair value of marketable securities below original cost is considered to be other than temporary. In addition, the Company will research the future prospects of individual securities as necessary. As a result of these factors, as well as the Company’s intent and ability to hold these investments until their market price recovers, these investments are not considered other-than-temporarily impaired. During the years ended December 31, 2004, 2003 and 2002, the Company recognized other than temporary impairment losses of marketable securities of $0.3 million, $0.6 million and $2.7 million, respectively.
Index to Financial Statements EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
N. Supplemental Statements of Cash Flows Disclosures
(1) See Note H.
Index to Financial Statements EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
O. Selected Quarterly Financial Data (Unaudited)
(1) Operating revenues are seasonal in nature, with the peak sales periods generally occurring during the summer months. Comparisons among quarters of a year may not represent overall trends and changes in operations.
Index to Financial Statements
Item 9.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A.
Item 9A. Controls and Procedures
Evaluation of disclosure controls and procedures. During the period covered by this report, the Company’s chief executive officer and chief financial officer, after evaluating the effectiveness of the Company’s “disclosure controls and procedures” (as defined in the Securities Exchange Act of 1934 Rules 13a-15(e) and 15d-15(e)) as of December 31, 2004, (the “Evaluation Date”), concluded that as of the Evaluation Date, the Company’s disclosure controls and procedures (as required by paragraph (b) of the Securities Exchange Act of 1934 Rules 13a-15 or 15d-15) were adequate and designed to ensure that material information relating to the Company and the Company’s consolidated subsidiary would be made known to them by others within those entities.
Management’s Annual Report on Internal Control Over Financial Reporting. Included herein under the caption “Management Report on Internal Control Over Financial Reporting” on page 44 of this report.
Changes in internal control over financial reporting. There were no changes in the Company’s internal control over financial reporting in connection with the evaluation required by paragraph (d) of the Securities Exchange Act of 1934 Rules 13a-15 or 15d-15, that occurred during the quarter ended December 31, 2004, that materially affected, or that were reasonably likely to materially affect, the Company’s internal control over financial reporting.
Item 9B.
Item 9B. Other Information
None.
Index to Financial Statements
PART III
Item 10.
Item 10. Directors and Executive Officers of the Registrant
Information regarding directors is incorporated herein by reference from the Company’s definitive proxy statement for the 2005 Annual Meeting of Shareholders (the “2005 Proxy Statement”) under the heading “Nominee and Directors of the Company.” Information regarding executive officers of the Company, included herein under the caption “Executive Officers of the Registrant” in Part I, Item 1 above, is incorporated herein by reference.
The information concerning the identification of our standing audit committee required by this Item is incorporated by reference from the 2005 Proxy Statement under the caption “Committees” under the heading “Directors’ Meetings, Compensation, Committees, Independence and Corporate Governance Matters,” and under the heading “Audit Committee Report.”
The information concerning our audit committee financial experts required by this Item is incorporated by reference from the 2005 Proxy Statement under the caption “Committees” under the heading “Directors’ Meetings, Compensation, Committees, Independence and Corporate Governance Matters.”
The information concerning compliance with Section 16(a) of the Exchange Act required by this Item is incorporated by reference from the 2005 Proxy Statement under the caption “Section 16(a) Beneficial Ownership Reporting Compliance” under the heading “Security Ownership of Certain Beneficial Owners and Management.”
We have adopted a Code of Ethics that is incorporated by reference from the 2005 Proxy Statement under the caption “Corporate Governance Matters” under the heading “Directors’ Meetings, Compensation, Committees, Independence and Corporate Governance Matters.”
Item 11.
Item 11. Executive Compensation
Incorporated herein by reference from the 2005 Proxy Statement under the caption “Executive Compensation” under the heading “Certain Additional Information.”
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management
Incorporated herein by reference from the 2005 Proxy Statement under the heading “Security Ownership of Certain Beneficial Owners and Management.”
Index to Financial Statements Equity Compensation Plan Information
Item 13.
Item 13. Certain Relationships and Related Transactions
Incorporated herein by reference from the 2005 Proxy Statement under the heading “Certain Business Transactions.”
Item 14.
Item 14. Principal Accounting Fees and Services
Incorporated herein by reference from the 2005 Proxy Statement under the heading “Independent Auditors.”
PART IV
Item 15.
Item 15. Exhibits and Financial Statement Schedules
(a) Documents filed as a part of this report:
Certain of the following documents are filed herewith. Certain other of the following exhibits have heretofore been filed with the Securities and Exchange Commission, and, pursuant to Rule 12b-32 and Regulation 201.24, are incorporated herein by reference.
Index to Financial Statements INDEX TO EXHIBITS
Index to Financial Statements
Index to Financial Statements
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Index to Financial Statements
* Filed herewith.
 Ten agreements, dated as of February 7, 2002, substantially identical in all material respects to this Exhibit, have been entered into with Terry D. Bassham; J. Frank Bates; Raul A. Carrillo, Jr.; Gary R. Hedrick; Kathryn Hood; Helen Williams Knopp; Kerry B. Lore; Robert C. McNiel; Hector R. Puente; and Guillermo Silva; officers of the Company.
Two agreements, dated as of July 15, 2002, substantially identical in all material respects to this Exhibit, have been entered into with Fernando J. Gireud and John A. Whitacre; officers of the Company.
 Nine agreements, dated as of February 28, 2001, substantially identical in all material respects to this Exhibit, have been entered into with Terry D. Bassham; J. Frank Bates; Gary R. Hedrick; Kathryn Hood; John C. Horne; Helen Williams Knopp; Kerry B. Lore; Robert C. McNiel; and Guillermo Silva; officers of the Company.
One agreement, dated as of November 8, 2001, identical in all material respects to this exhibit, has been entered into with Gary R. Hedrick; officer of the Company.
Index to Financial Statements Nine agreements, dated as of February 28, 2002, substantially identical in all material respects to this Exhibit, have been entered into with Terry D. Bassham; J. Frank Bates; Gary R. Hedrick; Kathryn Hood; Helen Williams Knopp; Kerry B. Lore; Robert C. McNiel; Hector R. Puente; and Guillermo Silva; officers of the Company.
Two agreements, dated as of July 15, 2002, substantially identical in all material respects to this Exhibit, have been entered into with Fernando J. Gireud and John A. Whitacre; officers of the Company.
Two agreements, dated as of December 4, 2003, substantially identical in all respects to this Exhibit, have been entered into with Steven P. Busser and Scott D. Wilson; officers of the Company.
 Two agreements, dated January 3, 1998, identical in all material respects to this exhibit, have been entered into with J. Frank Bates, Terry Bassham and Gary R. Hedrick; officers of the Company.
One agreement, dated as of May 28, 1999, identical in all material respects to this exhibit, has been entered into with Helen Knopp; officer of the Company.
Two agreements, dated as of January 3, 2000, identical in all material respects to this exhibit, have been entered into with John C. Horne and Terry Bassham; officers of the Company.
One agreement, dated as of April 23, 2001, identical in all material respects to this exhibit, has been entered into with Hector Puente; officer of the Company.
One agreement, dated as of November 5, 2001, identical in all material respects to this exhibit, has been entered into with Gary R. Hedrick; officer of the Company.
One agreement, dated as of November 12, 2001, identical in all material respects to this exhibit, has been entered into with Terry Bassham; officer of the Company.
One agreement, dated as of November 26, 2001, identical in all material respects to this exhibit, has been entered into with J. Frank Bates; officer of the Company.
Three agreements, dated as of May 10, 2001, identical in all material respects to this exhibit, have been entered into with Kathryn Hood, Kerry B. Lore and Guillermo Silva, Jr.; officers of the Company.
One agreement, dated as of January 14, 2002, identical in all material respects to this exhibit, has been entered into with Raul A. Carrillo, Jr.; officer of the Company.
Two agreements, dated as of July 15, 2002, identical in all material respects to this exhibit, have been entered into with Fernando J. Gireud and John A. Whitacre; officers of the Company.
Two agreements, dated as of December 4, 2003, identical in all material respects to this exhibit, have been entered into with Steven P. Busser and Scott D. Wilson; officers of the Company.
Index to Financial Statements
 In lieu of non-employee director cash compensation, twelve agreements, dated as of January 1, 2002; April 1, 2002; July 1, 2002; and October 1, 2002; substantially identical in all material respects to this Exhibit, have been entered into with Kenneth Heitz; Patricia Z. Holland-Branch; and Charles A. Yamarone; directors of the Company.
In lieu of non-employee director cash compensation, nine agreements, dated as of January 1, 2003; April 1, 2003; and July 1, 2003; substantially identical in all material respects to this Exhibit, have been entered into with Kenneth Heitz; Patricia Z. Holland-Branch; and Charles A. Yamarone; directors of the Company.
Twelve agreements, dated as of May 21, 2003, substantially identical in all material respects to this Exhibit, were entered into with George W. Edwards, Jr.; Ramiro Guzman; James W. Harris; Kenneth R. Heitz; James W. Cicconi; Patricia Z. Holland-Branch; Michael K. Parks; Eric B. Siegel; Stephen N. Wertheimer; Charles A. Yamarone; James A. Cardwell; and Wilson K. Cadman; directors of the Company.
In lieu of non-employee director cash compensation, four agreements dated as of October 1, 2003, substantially identical in all material respects to this Exhibit, have been entered into with James W. Cicconi; Kenneth R. Heitz; Patricia Z. Holland-Branch; and Charles A. Yamarone; directors of the Company.
In lieu of non-employee director cash compensation, three agreements, dated as of January 2, 2004; and April 1, 2004, substantially identical in all material respects to this Exhibit, have been entered into with Kenneth R. Heitz; Patricia Z. Holland-Branch; and Charles A. Yamarone; directors of the Company.
Eleven agreements, dated as of May 5, 2004, substantially identical in all material respects to this Exhibit, were entered into with George W. Edwards, Jr.; Ramiro Guzman; James W. Harris; Kenneth R. Heitz; James W. Cicconi; Patricia Z. Holland-Branch; Michael K. Parks; Eric B. Siegel; Stephen N. Wertheimer; Charles A. Yamarone; and J. Robert Brown; directors of the Company.
In lieu of non-employee director cash compensation, four agreements, dated as of July 1, 2004 and October 1, 2004, substantially identical in all material respects to this Exhibit, have been entered into with Kenneth R. Heitz and Patricia Z. Holland-Branch; directors of the Company.
 Eight agreements, dated as of May 8, 1997, identical in all material respects to this Exhibit have been entered into with George W. Edwards, Jr.; Ramiro Guzman; James W. Harris; Kenneth R. Heitz; Michael K. Parks; Eric B. Siegel; Stephen N. Wertheimer and Charles A. Yamarone; directors of the Company.
Ten agreements, dated as of May 29, 1998, identical in all material respects to this Exhibit have been entered into with George W. Edwards, Jr.; James W. Cicconi; Ramiro Guzman; James W. Harris; Kenneth R. Heitz; Patricia Z. Holland-Branch; Michael K. Parks; Eric B. Siegel; Stephen N. Wertheimer and Charles A. Yamarone; directors of the Company.
Index to Financial Statements In lieu of non-employee director cash compensation, two agreements, dated as of July 1, 2002 and October 1, 2002, substantially identical in all material respects to this Exhibit, have been entered into with Kenneth Heitz; director of the Company.
In lieu of non-employee director cash compensation, two agreements, dated as of January 1, 2003 and April 1, 2003, substantially identical in all material respects to this Exhibit, have been entered into with Kenneth Heitz; director of the Company.
Index to Financial Statements UNDERTAKING
Insofar as indemnification for liabilities arising under the Securities Act of 1933 may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act of 1933 and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question of whether such indemnification by it is against public policy as expressed in the Act and will be governed by the final adjudication of such issue.
Index to Financial Statements POWER OF ATTORNEY
KNOW ALL MEN BY THESE PRESENTS, that each of El Paso Electric Company, a Texas corporation, and the undersigned directors and officers of El Paso Electric Company, hereby constitutes and appoints Gary R. Hedrick, Terry Bassham, J. Frank Bates and Raul A. Carrillo, Jr., its, his or her true and lawful attorneys-in-fact and agents, for it, him or her and its, his or her name, place and stead, in any and all capacities, with full power to act alone, to sign this report and any and all amendments to this report, and to file each such amendment to this report, with all exhibits thereto, and any and all documents in connection therewith, with the Securities and Exchange Commission, hereby granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform any and all acts and things requisite and necessary to be done in and about the premises, as fully to all intents and purposes as it, he or she might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or any of them, may lawfully do or cause to be done by virtue hereof.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on the 11th day of March 2005.
EL PASO ELECTRIC COMPANY
By:
/s/ GARY R. HEDRICK
Gary R. Hedrick
President and Chief Executive Officer
(Principal Executive Officer)
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated.