Item 1. Business
General
El Paso Electric Company is a public utility engaged in the generation, transmission and distribution of electricity in an area of approximately 10,000 square miles in west Texas and southern New Mexico. The Company also serves wholesale customers in Texas, New Mexico, California and Mexico and through its subsidiary, MiraSol Energy Services, Inc., offers a variety of services to reduce energy use and/or lower energy costs. 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, 2001, the Company’s energy sources consisted of approximately 49% nuclear fuel, 32% natural gas, 8% coal, 11% purchased power and less than 1% generated by wind turbines.
The Company serves approximately 309,000 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 52% and 7%, respectively, of the Company’s electric utility operating revenues for the year ended December 31, 2001). In addition, the Company’s wholesale sales include sales for resale to the Imperial Irrigation District, Texas-New Mexico Power Company and the Comision Federal de Electricidad de Mexico, as well as sales to power marketers and other electric utilities. Principal industrial and other large customers of the Company include steel production, copper and oil refining, and United States military installations, including the United States Army Air Defense Center at Fort Bliss in Texas and White Sands Missile Range and Holloman Air Force Base in New Mexico.
The Company’s principal offices are located at the Stanton Tower, 100 North Stanton, El Paso, Texas 79901 (telephone 915-543-5711). The Company was incorporated in Texas in 1901. As of March 11, 2002, the Company had approximately 1,000 employees, 31% of whom are covered by a collective bargaining agreement.
Facilities
The Company’s net installed generating capacity of approximately 1,500 MW consists of approximately 600 MW from Palo Verde Units 1, 2 and 3, 482 MW from its Newman Power Station, 246 MW from its Rio Grande Power Station, 104 MW from Four Corners Units 4 and 5, 68 MW from its Copper Power Station and 1.32 MW from Hueco Mountain Wind Ranch.
Palo Verde Station
The Company owns a 15.8% interest in each of the three nuclear generating units and Common Facilities at Palo Verde, located 50 miles west of Phoenix, Arizona. The Palo Verde Participants include the Company and six other utilities: APS, Southern California Edison Company, PNM, Southern California Public Power Authority, Salt River Project Agricultural Improvement and Power District 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 proportionate share of fuel, other operations, maintenance and capital costs. The ANPP Participation Agreement provides that if a participant fails to meet its payment obligations, each non-defaulting participant shall pay its proportionate share of the payments owed by the defaulting participant.
Decommissioning. Pursuant to the ANPP Participation Agreement and federal law, the Company must fund its share of the estimated costs to decommission Palo Verde Units 1, 2 and 3, including the Common Facilities, over their estimated useful lives of 40 years (to 2024, 2025 and 2027, respectively). The Company’s funding requirements are determined periodically based upon engineering cost estimates performed by outside engineers retained by APS.
In December 2001, the Palo Verde Participants received a preliminary version of the 2001 decommissioning study. The 2001 preliminary study determined that the Company will have to fund approximately $312.2 million (stated in 2001 dollars) to cover its share of decommissioning costs. The previous cost estimate from a 1998 study determined that the Company would have to fund approximately $280.5 million (stated in 1998 dollars). The 2001 estimate reflects a 11.3% increase from the 1998 estimate primarily due to increases in estimated costs for site restoration at each unit, spent fuel storage after operations have ceased and for the Unit 2 steam generator storage. The Company anticipates Palo Verde Participant approval of the 2001 preliminary study in the second quarter of 2002 with no significant changes. See “Spent Fuel Storage” below.
Although the 2001 preliminary study was based on the latest available information, there can be no assurance that decommissioning cost estimates will not continue to increase in the future or that regulatory requirements will not change. In addition, until a new low-level radioactive waste repository opens and operates for a number of years, estimates of the cost to dispose of low-level radioactive waste are subject to significant uncertainty. The decommissioning study is updated every three years and a new study is expected to be completed in 2004. See “Disposal of Low-Level Radioactive Waste” below.
Historically, regulated utilities such as the Company have been permitted to collect in rates the costs of nuclear decommissioning. Under deregulation legislation in both Texas and New Mexico, the Company expects to continue to be able to collect from customers the costs of decommissioning. The collection mechanism in both states will be a “non-bypassable wires charge” through which all customers, even those who choose to purchase energy from a supplier other than the Company, will pay a fee to the Company’s electric distribution subsidiary. The amount of this fee will be approved by the Texas and New Mexico Commissions and will cover decommissioning, among other things. In the Company’s case, the fee will begin to be collected in Texas following the end of the Freeze Period in August 2005 and in New Mexico in 2007, which is the current date for the beginning of retail deregulation. See “Regulation - Texas Regulatory Matters - Deregulation” for further discussion. While the Company is entitled to collect decommissioning costs in full under Texas law, there is some uncertainty in New Mexico as to the ability to collect 100% of such costs. See “Regulation - New Mexico Regulatory Matters.”
Spent Fuel Storage. The spent fuel storage facilities at Palo Verde will have sufficient capacity to store all fuel expected to be discharged from normal operation of all three Palo Verde units through 2003. Alternative on-site storage facilities are currently being constructed to supplement existing facilities. Spent fuel will be removed from the original facilities as necessary and placed in special storage casks which will be stored at the new facilities until accepted by the DOE for permanent disposal. The alternative facilities will be built in stages to accommodate casks on an as needed basis and are expected to be available for use by the end of 2002. 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. In November 1989, the DOE 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.
In July 1998, APS filed, on behalf of all Palo Verde Participants, a petition for review with the United States Court of Appeals for the District of Columbia Circuit seeking confirmation that findings by the Circuit Court in a prior case brought by Northern States Power regarding the DOE’s failure to comply with its obligation to begin accepting spent nuclear fuel would apply to all spent nuclear fuel contract holders. The Circuit Court held APS’ petition in abeyance pending the United States Supreme Court’s decision to review the Northern States Power case. In November 1998, the Supreme Court denied review of this case. The Circuit Court subsequently dismissed APS’ petition after the Circuit Court issued clarifying orders essentially granting the relief sought by APS. APS is monitoring pending litigation between the DOE and other nuclear operators before initiating further legal proceedings or other procedural measures on behalf of the Palo Verde Participants to enforce the DOE’s statutory and contractual obligations. The Company is unable to predict the outcome of these matters at this time.
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 expensed as incurred until an agreement is reached with the DOE for recovery of these costs. However, the Company cannot predict when, if ever, these additional costs will be recovered from the DOE.
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. However, 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 some degradation in the steam generator tubes of each unit. APS has undertaken an ongoing investigation and analysis and has performed corrective actions designed to mitigate further degradation. Corrective actions have included changes in operational procedures designed to lower the operating temperatures of the units, chemical cleaning and the implementation of other technical improvements. APS believes its remedial actions have slowed the rate of tube degradation.
The projected service lives of the units’ steam generators are reassessed by APS periodically in conjunction with inspections made during scheduled outages of the Palo Verde units. In December 1999, the Palo Verde Participants unanimously approved installation of new steam generators in Unit 2. This decision was based on an analysis of the net economic benefit from expected improved performance of the unit and the need to realize continued production from that unit over its full licensed life. APS has advised the Company that the fabrication of Unit 2 steam generators is proceeding on schedule, with plans to install the replacement steam generators at Unit 2 during the fall 2003 refueling outage. The Company’s portion of total costs associated with construction and installation of new steam generators in Unit 2 is currently estimated not to exceed $45 million, including approximately $4.9 million of replacement power costs.
Recently, APS discovered potential accelerated degradation in the tubes in Units 1 and 3 and has tentatively concluded that it may be economically desirable to replace the steam generators at those units. While the economic analysis is not yet complete, and a final determination of whether Units 1 and 3 will require steam generator replacement to operate over their full licensed lives has not yet been made, the Company and the other participants have approved the expenditure of $25.6 million (the Company’s portion being $4.04 million) in 2002 to procure long lead time materials for fabrication of a spare set of steam generators for either Unit 1 or 3. The Company also anticipates a request from APS in the summer of 2002 for approval to spend up to $70.0 million (the Company’s portion being $11.0 million) for the fabrication of one spare set of steam generators to be used in either Unit 1 or 3. These actions will provide the Palo Verde participants an option to replace the steam generators at either Unit 1 or 3 as early as fall 2005, should they ultimately choose to do so.
If the participants decide to proceed with steam generator replacement at both Units 1 and 3, APS has estimated that the Company’s portion of the fabrication and installation costs and associated power uprate modifications would range from $72.0 to $80.0 million over the next six years. The Company expects its portion would be funded with internally generated cash. Any such replacements would also require the unanimous approval of the Palo Verde participants.
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 may request recovery of a portion of these costs through regulated rates in New Mexico. See “Regulation - New Mexico Regulatory Matters” for further discussion. Finally, the Company cannot assure that it will be able to recover these capital costs through its wholesale power rates or its competitive retail rates that become applicable after the start of competition. See also Part II, Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Overview.”
Liability and Insurance Matters. In 1957, Congress enacted the Price-Anderson Act as an amendment to the Atomic Energy Act to provide a system of financial protection for persons who may be injured and persons who may be liable for a nuclear incident. The amount of DOE indemnification currently available under the act is $9.43 billion. Additionally, the Palo Verde Participants have public liability insurance against nuclear energy hazards up to the full limit of liability under the Price-Anderson Act. The insurance consists of $200 million of primary liability insurance provided by commercial insurance carriers, with the balance being provided by an industry-wide retrospective assessment program, pursuant to which industry participants would be required to pay a retrospective assessment to cover any loss in excess of $200 million. Effective August 1998, the maximum retrospective assessment per reactor for each nuclear incident is approximately $88.1 million, subject to an annual limit of $10 million per incident. Based upon the Company’s 15.8% interest in Palo Verde, the Company’s maximum potential retrospective assessment per incident is approximately $41.8 million for all three units with an annual payment limitation of approximately $4.7 million.
The Price-Anderson Act was amended in 1988 to extend its term until August 1, 2002. On that date, the DOE’s authority to provide DOE indemnification in a contract will expire. Accordingly, if the Price-Anderson Act is not extended, the DOE indemnification will not cover activity under any contract entered into after August 1, 2002. That expiration will not affect activity under a contract in effect on that date. In November 2001, the U.S. House of Representatives voted in favor of reauthorization of the Price-Anderson Act. The measure, H.R. 2983, extends Price-Anderson coverage for an additional fifteen years. The U.S. Senate could take up the measure early in the second session of the 107th Congress.
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. Finally, the Company 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 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 246 MW. The units operate primarily on natural gas, but can also operate on fuel oil.
Four Corners Station
The Company owns a 7% interest, or approximately 104 MW, in Units 4 and 5 at Four Corners, located in northwestern New Mexico. The two coal-fired generating units each have a total generating capacity of 739 MW. The Company shares power entitlements and certain allocated costs of the two units with APS (the Four Corners operating agent) and the other participants.
Four Corners is located on land held on easements from the federal government and a lease from the Navajo Nation that expires in 2016. Certain of the facilities associated with Four Corners, including transmission lines and almost all of the contracted coal sources, are also located on Navajo land. Units 4 and 5 are located adjacent to a surface-mined supply of coal.
Copper Power Station
The Company’s Copper Power Station, located in El Paso, Texas, consists of a 68 MW combustion turbine used primarily to meet peak demands. The unit operates primarily on natural gas, but can also operate on fuel oil. The Company leases the combustion turbine and other generation equipment at the station under a lease that expires in July 2005, with an extension option for two additional years.
Hueco Mountain Wind Ranch
The Company’s Hueco Mountain Wind Ranch, located in Hudspeth County, east of El Paso County and adjacent to Horizon City, currently consists of two wind turbines with a total capacity of 1.32 MW.
Transmission and Distribution Lines and Agreements
The Company owns or has significant ownership interests in four major 345 kV transmission lines, three 500 kV lines in Arizona, and owns the distribution network within its retail service area. The Company is also a party to various transmission and power exchange agreements that, together with its owned transmission lines, enable the Company to obtain its energy entitlements from its remote generation sources at Palo Verde and Four Corners. Pursuant to standards established by the North American Electric Reliability Council, the Company operates its transmission system in a way that allows it to maintain complete system integrity in the event of any one of these transmission lines being out of service.
Springerville-Diablo Line. The Company owns a 310-mile, 345 kV transmission line from TEP’s Springerville Generating Plant near Springerville, Arizona, to the Luna Substation near Deming, New Mexico, and to the Diablo Substation near Sunland Park, New Mexico, providing an interconnection with TEP for delivery of the Company’s generation entitlements from Palo Verde and, if necessary, Four Corners.
Arroyo-West Mesa Line. The Company owns a 202-mile, 345 kV transmission line from the Arroyo Substation located near Las Cruces, New Mexico, to PNM’s West Mesa Substation located near Albuquerque, New Mexico. This is the primary delivery point for the Company’s generation entitlement from Four Corners, which is transmitted to the West Mesa Substation over approximately 150 miles of transmission lines owned by PNM.
Greenlee-Newman Line. As a participant in the Southwest New Mexico Transmission Project Participation Agreement, the Company owns 40% of a 60-mile, 345 kV transmission line from TEP’s Greenlee Substation in Arizona to the Hidalgo Substation near Lordsburg, New Mexico, 57.2% of a 50-mile, 345 kV transmission line between the Hidalgo Substation and the Luna Substation near Deming, New Mexico, and 100% of an 86-mile, 345 kV transmission line between the Luna Substation
and the Newman Power Station. These lines provide an interconnection with TEP for delivery of the Company’s entitlements from Palo Verde and, if necessary, Four Corners.
AMRAD-Eddy County Line. The Company owns 66.7% of a 125-mile, 345 kV transmission line from the AMRAD Substation near Oro Grande, New Mexico, to the Company’s and TNP’s high voltage direct current terminal at the Eddy County Substation near Artesia, New Mexico. This terminal enables the Company to connect its transmission system to that of SPS, providing the Company with access to emergency power from SPS and power markets to the east.
Palo Verde Transmission and Switchyard. The Company owns 18.7% of two 45-mile, 500 kV lines from Palo Verde to the Westwing Substation and a 75-mile, 500 kV line from Palo Verde to the Kyrene Substation. These lines provide the Company with a transmission path for delivery of power from Palo Verde. The Company will also own 18.7% of a new 500 kV switchyard that is under construction adjacent to the southern edge of the Palo Verde 500 kV switchyard. This new switchyard is being built to accommodate the addition of new generation and transmission in the Palo Verde area and will intersect with the Company’s Kyrene 500 kV transmission line. The construction cost of the new switchyard will be paid by certain third-party users.
Environmental Matters
The Company is subject to regulation with respect to air, soil and water quality, solid waste disposal and other environmental matters by federal, state, tribal and local authorities. Those authorities govern current facility operations and exercise continuing jurisdiction over facility modifications. Environmental regulations can change rapidly and are difficult to predict. Substantial expenditures may be required to comply with these regulations. The Company analyzes the costs of its obligations arising from environmental matters on an ongoing basis, and management believes it has made adequate provision in its financial statements to meet such obligations. Currently, the Company has provision for environmental remediation obligations of approximately $0.6 million. However, unforeseen expenses associated with compliance could have a material adverse effect on the future operations and financial condition of the Company.
Construction Program
Utility construction expenditures reflected in the following table consist primarily of expanding and updating the transmission and distribution systems and the cost of capital improvements and replacements at Palo Verde and other generating facilities, including the replacement of the Palo Verde Unit 2 steam generators and long lead time materials for one additional set of steam generators. APS has estimated that if approved by the Palo Verde Participants, the Company’s share of additional costs for the replacement of steam generators and power uprate modifications for Palo Verde Units 1 and 3 would range from $72.0 to $80.0 million for the period 2002 through 2007. Replacement power costs expected to be incurred during replacements of Palo Verde steam generators are not included in construction costs. The Company is also evaluating the future need for additional generation resources by 2006. Estimates for the addition of a new generating unit from 2002 through 2006 is approximately $61.0 million. No final plan, however, for a new generation source has been adopted.
The Company’s estimated cash construction costs for 2002 through 2005 are approximately $270 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)
Does not include possible costs for replacement of Units 1 and 3 steam generators or additional generation.
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. However, from October 1998 to June 2001, the Company’s New Mexico fixed fuel factor had been incorporated into its frozen base rates pursuant to the New Mexico Settlement Agreement. Therefore, there were no fuel reconciliation filings before the New Mexico Commission during that time period. See “Regulation - Texas Regulatory Matters” and “- New Mexico Regulatory Matters.”
Nuclear Fuel
The nuclear fuel cycle for Palo Verde consists of the following stages: the mining and milling of uranium ore to produce uranium concentrates; the conversion of the uranium concentrates to uranium hexaflouride; the enrichment of uranium hexaflouride; the fabrication of fuel assemblies; the utilization of the fuel assemblies in the reactors; and the storage and disposal of the spent fuel. The Palo Verde Participants have contracts for uranium concentrates anticipated to be sufficient to meet 100% of Palo Verde’s operational requirements in 2002 and 67% in 2003. Spot purchases on the uranium market will be made, as appropriate, for any uranium concentrates that may not be obtained through these contracts. The Palo Verde Participants also have contracts in place for conversion and enrichment services to meet all of the plant requirements in 2002 and 2003. The Palo Verde Participants have a new enrichment uranium product contract that will furnish up to 100% of Palo Verde’s operational requirements for uranium concentrates, conversion services and enrichment services from 2004 through 2008. This contract could also provide 100% of enrichment services in 2009 and 2010. The Palo Verde Participants have contracts for fuel assembly fabrication services through 2015 for each Palo Verde unit.
Nuclear Fuel Financing. Pursuant to the ANPP Participation Agreement, the Company owns an undivided interest in nuclear fuel purchased in connection with Palo Verde. The Company has available a total of $100 million under a revolving credit facility that provides for both working capital and up to $70 million for the financing of nuclear fuel. At December 31, 2001, approximately $48.3 million had been drawn to finance nuclear fuel. This financing is accomplished through a trust that borrows under the facility to acquire and process the nuclear fuel. The Company is obligated to repay the trust’s borrowings with interest and has secured this obligation with First Mortgage Collateral Series Bonds. In the Company’s financial statements, the assets and liabilities of the trust are reported as assets and liabilities of the Company.
Natural Gas
The Company manages its natural gas requirements through a combination of long-term contracts and market purchases. In 2001, the Company’s natural gas requirements at the Rio Grande Power Station were met with both short-term and long-term natural gas purchases from various suppliers. Interstate gas is delivered under a firm transportation agreement which expires in 2005. The Company anticipates it will continue to purchase natural gas at market prices on a monthly basis for a portion of the fuel needs for the Rio Grande Power Station for the near term. To complement those monthly purchases in 2002, the Company has entered into a one-year and a two-year fixed-price gas supply contract. 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.
In 2001, natural gas for the Newman and Copper Power Stations was supplied primarily pursuant to an intrastate natural gas contract that became effective January 1, 1997. However, the vendor has given the Company a notice of termination of the current contract effective December 2002 and indicated its desire to negotiate a new agreement. The Company is currently negotiating a new contract with its current vendor and evaluating other options including use of its interstate pipeline supply for 2003 and beyond. Based upon pipeline capacity and natural gas availability, the Company believes that a new contract which meets the Company’s needs will be negotiated and effective January 2003. The Company will also continue to evaluate short-term natural gas supplies to maintain a reliable and economical supply for the Newman and Copper Power Stations.
Coal
APS, as operating agent for Four Corners, purchases Four Corners’ coal requirements from a supplier with a long-term lease of coal reserves owned by the Navajo Nation. The lease expires in 2004 and can be extended for an additional 15 years. Based upon information from APS, the Company believes that Four Corners has sufficient reserves of coal to meet the plant’s operational requirements for its useful life.
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. For 2001, the Company purchased 60 MW of firm on-peak energy for June through September at the Palo Verde switchyard. In addition, the Company purchased monthly 103 MW of firm on-peak block energy. Other purchases of shorter duration were made primarily to replace the Company’s generation resources during planned and unplanned outages.
As of March 11, 2002, the Company had entered into the following agreements with counterparties for forward fixed price firm purchases of electricity:
(1)
Portions of these contracts include fuel adjustment clauses.
Enron Power Marketing, Inc. (“Enron”) is a counterparty to 50 MW of the 128 MW firm purchases for 2002. If Enron fails to perform under that contract, the Company believes that it will be able to obtain replacement power at prices lower than those payable to Enron under the contract. Enron is also the counterparty to the 60 MW contract for June through September 2002; however, this contract is fully offset by a 60 MW sale to Enron for the same price and time period. See “Power Sales Contracts.”
Operating Statistics
Regulation
General
In 1999, both Texas and New Mexico enacted electric utility industry restructuring laws requiring competition in certain functions of the industry and ultimately in the Company’s service area. Competition in New Mexico was scheduled to begin on January 1, 2002 under the New Mexico Restructuring Law. On March 8, 2001, however, the New Mexico Restructuring Law was amended to delay the start of competition for five years until January 1, 2007. Under the Texas Restructuring Law, the Company’s Texas service area is exempt from competition until the expiration of the Freeze Period in August 2005.
The Company continues to work to become more competitive in response to these restructuring laws and to other regulatory, economic and technological changes occurring throughout the industry. Deregulation of the production of electricity and related services and increasing customer demand for lower priced electricity and other energy services have accelerated the industry’s movement toward more competitive pricing and cost structures. Those competitive pressures could result in the loss of customers and diminish the ability of the Company to fully recover its investment in generation assets. In January 2002, competition was initiated in most parts of Texas. As a result, the Company may face increasing pressure on its retail rates and its rate freeze under the Texas Rate Stipulation. The Company’s results of operations and cash flows may be adversely affected if it cannot maintain its current retail rates.
Texas Regulatory Matters
The rates and services of the Company in Texas municipalities are regulated by those municipalities and in unincorporated areas by the Texas Commission. The largest municipality in the Company’s service area is the City of El Paso. The Texas Commission has exclusive appellate jurisdiction to review municipal orders and ordinances regarding rates and services in Texas and jurisdiction over certain other activities of the Company. The decisions of the Texas Commission are subject to judicial review.
Deregulation. The Texas Restructuring Law requires an electric utility to separate its power generation activities from its transmission and distribution activities by January 1, 2002. In January 2002, competition was instituted in most parts of Texas. Nonetheless, the Texas Restructuring Law specifically recognizes and preserves the substantial benefits the Company bargained for in its Texas Rate Stipulation and Texas Settlement Agreement, exempting the Company’s Texas service area from retail competition, and preserving rates at their current levels until the end of the Freeze Period. At the end of the Freeze Period, the Company will be subject to retail competition and at that time will be permitted to recover nuclear decommissioning costs in rates, but will have no further claim for recovery of stranded costs. Stated simply, stranded costs are the positive difference, if any, between the book value of electric generating assets, including long-term purchase power contracts, and the market value of those assets. The Company believes that its continued ability to provide bundled electric service at current rates in its Texas service area will allow the Company to collect its Texas jurisdictional stranded costs because (i) the Company does not have power purchase contracts that extend beyond 2005 and
(ii) the Company revalued its utility plant under fresh start accounting in 1996 so that the generation assets would be reflective of projected market values in a deregulated environment.
Although the Company is not subject to the Texas restructuring requirements until the expiration of the Freeze Period, the Company sought Texas Commission approval of the Company’s corporate restructuring in anticipation of complying with the restructuring requirements of the New Mexico Restructuring Law. In December 2000, the Texas Commission approved the Company’s corporate restructuring plan. However, the amended New Mexico Restructuring Law now prohibits the separation of the Company’s generation activities from its transmission and distribution activities before September 1, 2005, directly conflicting with the Texas Restructuring Law requiring separation of these activities after the expiration of the Freeze Period in August 2005. Accordingly, in either 2004 or 2005, the Company will seek New Mexico Commission approval to separate the Company’s generation activities from its transmission and distribution activities to allow the Company to comply with the Texas Restructuring Law requirements.
Texas Rate Stipulation and Texas Settlement Agreement. The Texas Rate Stipulation and Texas Settlement Agreement govern the Company’s rates for its Texas customers, but do not deprive the Texas regulatory authorities of their jurisdiction over the Company during the Freeze Period. However, the Texas Commission determined that the rate freeze is in the public interest and results in just and reasonable rates. Further, the signatories to the Texas Rate Stipulation (other than the Texas Office of Public Utility Counsel and the State of Texas) agreed not to seek to initiate an inquiry into the reasonableness of the Company’s rates during the Freeze Period and to support the Company’s entitlement to rates at the freeze level throughout the Freeze Period. The Company believes, but cannot assure, that its cost of service will support rates at or above the freeze level throughout the Freeze Period and, therefore, does not believe any attempt to reduce the Company’s rates would be successful. However, during the Freeze Period, the Company is precluded from seeking base rate increases in Texas, even in the event of increased operating or capital costs. In the event of a merger, the parties to the Texas Rate Stipulation retain all rights provided in the Texas Rate Stipulation, the right to participate as a party in any proceeding related to the merger, and the right to pursue a reduction in rates below the freeze level to the extent of post-merger synergy savings.
Fuel. Although the Company’s base rates are frozen in Texas, pursuant to Texas Commission rules and the Texas Rate Stipulation, the Company can request adjustments to its fuel factor to more accurately reflect projected energy costs associated with the provision of electricity as well as seek recovery of past undercollections of fuel revenues.
In October 2001, the Texas Commission approved a unanimous settlement agreement (the “Texas Fuel Settlement”) between the Company and the parties which had intervened, including the City of El Paso, which increased the Texas fuel factor to $0.02494 per kWh. This factor was implemented on an interim basis in April 2001 and increased fuel revenue collections by $11.7 million for the year ended December 31, 2001. The Texas Fuel Settlement also provides for the surcharge of underrecovered fuel costs as of December 31, 2000 of approximately $15 million plus interest over an 18-month period. The fuel surcharge was implemented on an interim basis beginning with the first billing cycle in June 2001. The Texas Fuel Settlement provides for the final agreement between the parties for the non-recovery of certain purchased power contract costs as well as the favorable disposition of previously unrecognized Palo Verde performance rewards, including interest. These provisions taken together did not have a material effect on the Company’s results of operations and resulted in an $11.0 million increase in Net Undercollection of Fuel Revenues and a $10.5 million increase in Deferred
Credits and Other Liabilities - Other, which were recorded in June 2001. The Company also agreed to a prospective change in the Palo Verde performance standards, which materially reduced the potential for future rewards and penalties on a symmetrical basis.
The Company anticipates terminating its interim fuel surcharge earlier than expected and anticipates filing a petition with the Texas Commission in April 2002 to end that surcharge of underrecovered fuel costs. The interim fuel surcharge, as well as the Company’s other energy expenses through year-end 2001, will be subject to final review by the Texas Commission in the Company’s next fuel reconciliation proceeding, which is expected to be filed in June 2002. The Texas Commission staff, local regulatory authorities such as the City of El Paso, and customers are entitled to intervene in a fuel reconciliation proceeding and to challenge the prudence of fuel and purchased power expenses.
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. As mentioned above these performance standards were materially altered during 2001. 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. The Company has calculated approximately $1 million of performance rewards for the 2001 reporting period. These rewards will be included, along with energy costs incurred, as part of the Texas Commission’s review during the periodic fuel reconciliation proceedings discussed above. Those performance rewards will not be recorded on the Company’s books until the Texas Commission has ordered a final determination in a fuel reconciliation proceeding. Performance penalties are recorded when assessed as probable by the Company.
New Mexico Regulatory Matters
The New Mexico Commission has jurisdiction over the Company’s rates and services in New Mexico and over certain other activities of the Company, including prior approval of the issuance, assumption or guarantee of securities. The New Mexico Commission’s decisions are subject to judicial review. The largest city in the Company’s New Mexico service territory is Las Cruces.
Deregulation. In March 2001, the New Mexico Legislature amended the New Mexico Restructuring Law to postpone deregulation in New Mexico until January 1, 2007, and to prohibit the separation of a utility’s transmission and distribution activities from its existing generation activities prior to September 1, 2005. The amended New Mexico Restructuring Law permits utilities to form holding companies subject to New Mexico approval with conditions. It also allows the utility, until corporate separation occurs, to participate in unregulated generation activities if the generation is not intended to serve New Mexico retail customers.
The amended New Mexico Restructuring Law prohibiting the separation of the Company’s generation activities from its transmission and distribution activities prior to September 1, 2005 may conflict with the Texas Restructuring Law requiring separation of those activities after the expiration of the Freeze Period in August 2005. Accordingly, the Company is currently evaluating possible benefits, if any, of forming a holding company prior to 2005. The Company anticipates that it will seek
New Mexico Commission approval to separate the Company’s generation activities from its transmission and distribution activities in either 2004 or 2005 to allow the Company to restructure at the earliest time allowable.
The amended New Mexico law required the New Mexico Commission to approve previously filed applications to form holding companies to the extent that the applications do not conflict with the provisions of the law as amended and are otherwise in the public interest. Accordingly, in early April 2001, the Company filed its suggested amendments to its previously filed proposed corporate restructuring plan. The filing sought to conform the Company’s proposal with the requirements under the amended law which requires the regulated utility to continue to own all regulated generation currently owned and operated by the utility. On June 28, 2001, the New Mexico Commission issued its order approving formation of a holding company for the Company, but also placing thirty-eight conditions upon its approval. The conditions included numerous reporting and compliance requirements as well as strict prohibitions on certain intercompany activity. The Company sought rehearing on the order, which was denied without action by the Commission. The Company filed an appeal with the New Mexico Supreme Court on September 15, 2001. After reviewing the Company’s options in light of the Commission’s holding company order, the Company determined it was in its best interest to withdraw its request for a holding company and request that the Commission vacate the order. The Company, the New Mexico Commission and the Attorney General filed a joint motion asking the Court to dismiss the appeal so the Commission could vacate the order and allow the Company to withdraw its application. The Court dismissed the appeal on October 10, 2001, and the Commission vacated the order on December 18, 2001. Thus, the Company is no longer subject to the holding company conditions. The Company may request approval of a holding company at a later date, if and when needed, subject to whatever legal requirements are in effect at that time.
The New Mexico Restructuring Law allows the Company to recover reasonable, prudent and unmitigated costs that the Company would not have incurred but for its compliance with the New Mexico Restructuring Law. The March 2001 amendment to the New Mexico Restructuring Law did not address the recovery of transition costs spent to date. The Company cannot predict whether and to what extent the New Mexico Commission will allow the Company to recover these transition costs during the five year delay. Such costs, to the extent they are not capitalizable as fixed assets, are expensed as incurred.
Fuel. The New Mexico Settlement Agreement entered into in October 1998 eliminated the then existing fuel factor of $0.01949 per kWh incorporating it into frozen base rates. Accordingly, the Company was required to absorb any increases in fuel and purchased power (“energy”) expenses related to its New Mexico retail customers until new rates were implemented subsequent to the end of the rate freeze on April 30, 2001. The average energy costs incurred for New Mexico jurisdictional customers exceeded this fuel factor by a substantial amount. Therefore, on April 23, 2001, the Company filed a petition with the New Mexico Commission proposing a settlement that would implement a new fixed fuel factor and reinstate for a two-year period a fuel adjustment clause in lieu of a base rate increase (the “New Mexico Fuel Factor Agreement”). The New Mexico Commission allowed the Company to implement its New Mexico Fuel Factor Agreement on an interim basis, beginning on June 15, 2001, subject to final approval of the New Mexico Commission. The New Mexico Commission entered its final order on January 8, 2002, setting a fixed fuel factor of $0.01501 per kWh designed to increase revenues by approximately $19 million annually. The reinstatement of a fuel adjustment clause substantially mitigates the financial risk to the Company of any further energy cost increases over the two-year period of the agreement.
Due to the decrease in gas prices since mid-2001, on February 12, 2002, the Company filed a petition with the New Mexico Commission for a fuel factor decrease to $0.00420 per kWh. The New Mexico Commission issued an order approving that decrease on February 19, 2002. Under current projections the Company’s new fuel factor will decrease fuel revenue collections by approximately $15.5 million in 2002.
Federal Regulatory Matters
Federal Energy Regulatory Commission. The Company is subject to regulation by the FERC in certain matters, including rates for wholesale power sales, transmission of electric power and the issuance of securities.
Fuel. Under FERC regulations, the Company’s fuel factor is adjusted monthly for almost all FERC jurisdictional customers. Accordingly, any increase or decrease in energy expenses immediately flows through to such customers.
RTOs. On December 15, 1999, the FERC approved its final rule (“Order 2000”) on Regional Transmission Organizations (“RTOs”). Order 2000 strongly encourages, but does not require, public utilities to form and join RTOs. Order 2000 also proposes RTO startup by December 15, 2001. The Company is an active participant in the development of WestConnect, formerly known as the Desert Southwest Transmission and Reliability Operator. The Company believes WestConnect will qualify as an RTO under Order 2000. The Company intends, subject to the resolution of outstanding issues, to participate in WestConnect. As a participating transmission owner, the Company will transfer operations of its transmission system to WestConnect. The WestConnect proposal was submitted to the FERC on October 15, 2000. On March 1, 2001, the WestConnect proposal was updated to inform the FERC that the start of WestConnect operations would be delayed. WestConnect currently is scheduled to become operational by January 1, 2003. If WestConnect should fail to become operational, the Company would seek to participate in another RTO similar to WestConnect.
Department of Energy. The DOE regulates the Company’s exports of power to CFE in Mexico pursuant to a license granted by the DOE and a presidential permit. The DOE has determined that all such exports over international transmission lines shall be made in accordance with Order No. 888, which established the FERC rules for open access. The DOE is authorized to assess operators of nuclear generating facilities a share of the costs of decommissioning the DOE’s uranium enrichment facilities and for the ultimate costs of disposal of spent nuclear fuel. See “Facilities - Palo Verde Station - Spent Fuel Storage” for discussion of spent fuel storage and disposal costs.
Nuclear Regulatory Commission. The NRC has jurisdiction over the Company’s licenses for Palo Verde and regulates the operation of nuclear generating stations to protect the health and safety of the public from radiation hazards. The NRC also has the authority to conduct environmental reviews pursuant to the National Environmental Policy Act.
Sales for Resale
During 2001, the Company provided IID with 100 MW of firm capacity and associated energy and 50 MW of system contingent capacity and associated energy pursuant to a 17-year agreement which expires on April 30, 2002. The Company also provided TNP in 2001 with up to 25 MW of firm
capacity and associated energy pursuant to an agreement that expires on December 31, 2002. The contract allows TNP to specify a maximum annual amount up to 75 MW with one year’s notice. The Company received notice from TNP in December 2000 that TNP was electing to take 75 MW in 2002. The Company also sold 40 MW of firm capacity and associated energy to CFE during May 2001 and 100 MW during June through September 2001.
Power Sales Contracts
As of March 11, 2002, the Company had entered into the following agreements with various counterparties for forward firm sales of electricity:
The Company also has an agreement with a counterparty for power exchanges under which the Company will receive 80 MW of on-peak capacity and associated energy during 2002 at the Eddy County tie and concurrently deliver the same amount at Palo Verde and/or Four Corners. The on-peak exchange amount will decrease to 30 MW for 2003 through 2005. The agreement also gives the counterparty the option to deliver up to 133 MW of off-peak capacity and associated energy to the Company at the Eddy County tie from 2002 through 2005 in exchange for the same amount of energy concurrently delivered by the Company at Palo Verde and/or Four Corners. The Company will receive a guaranteed margin on any energy exchanged under the off-peak agreement. See “Purchased Power.”
Executive Officers of the Registrant
The executive officers of the Company as of March 11, 2002, were as follows:
The executive officers of the Company are elected annually and serve at the discretion of the Board of Directors.
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. See Part II, Item 8, “Financial Statements and Supplementary Data - Note F of Notes to Consolidated Financial Statements” for information regarding encumbrances against the principal properties of the Company.
In addition, the Company leases executive and administrative offices in El Paso, Texas. See Part II, Item 8, “Financial Statements and Supplementary Data - Note H of Notes to Consolidated Financial Statements” for information regarding the leased property.
Item 3.
Item 3. Legal Proceedings
The Company is a party to various legal actions. In many of these matters, the Company has excess casualty liability insurance that covers the various claims, actions and complaints. Based upon a review of these claims and applicable insurance coverage, the Company believes that none of these claims will have a material adverse effect on the financial position, results of operations and cash flows of the Company.
The Company’s federal income tax returns for the years 1996 through 1998 have been examined by the IRS. On October 3, 2001, the Company received the IRS notice of proposed deficiency. The primary audit adjustments proposed by the IRS related to (i) whether the Company was entitled to deduct payments made on emergence from Chapter 11 bankruptcy proceedings related to Palo Verde and (ii) the settlement of litigation in 1997 concerning a terminated merger during the Company’s bankruptcy. The Company has protested the audit adjustments through administrative appeals and believes that its treatment of the payments is supported by substantial legal authority. In the event that the IRS prevails, the resulting income tax and interest payments could be material to the Company’s financial position, results of operations and cash flows.
Item 4.
Item 4. Submission of Matters to a Vote of Security Holders
Not applicable.
PART II
Item 5.
Item 5. Market for Registrant’s Common Equity and Related Stockholder Matters
The Company’s common stock trades on the American Stock Exchange under the symbol “EE.” On September 25, 2000, the Company’s stock began trading in decimals in compliance with the Securities and Exchange Commission requirement that equity and option markets convert to decimal pricing systems. The high, low and close sales prices for the Company’s common stock, as reported in the consolidated reporting system of the American Stock Exchange, for the periods indicated below, were as follows:
As of March 11, 2002, there were 4,993 holders of record of the Company’s common stock. The Company does not anticipate paying dividends on its common stock in the near-term. The Company intends to continue its deleveraging and stock repurchase programs with the goal of improving its capital structure.
The Company’s Board of Directors previously approved two stock repurchase programs allowing the Company to purchase up to twelve million of its outstanding shares of common stock. On February 7, 2002, the Company’s Board of Directors approved a third stock repurchase program allowing the Company to purchase up to three million shares of common stock. As of March 11, 2002, the Company had repurchased 11,921,329 shares of common stock under these programs for approximately $133.9 million, including commissions. The Company expects to continue to make purchases primarily in the open market at prevailing prices and will also engage in private transactions, if appropriate. Any repurchased shares will be available for issuance under employee benefit and stock option plans, or may be retired.
Item 6.
Item 6. Selected Financial Data
As of and for the following periods (in thousands except for share data):
The selected financial data should be read in conjunction with Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and Item 8, “Financial Statements and Supplementary Data.”
Item 7.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Statements in this document, other than statements of historical information, are forward-looking statements that are made pursuant to the safe harbor provisions of the Private Securities Litigation Reform Act of 1995. Such forward-looking statements, as well as other oral and written forward-looking statements made by or on behalf of the Company from time to time, including statements contained in the Company’s filings with the Securities and Exchange Commission and its reports to shareholders, involve known and unknown risks and other factors which may cause the Company’s actual results in future periods to differ materially from those expressed in any forward-looking statements. Factors that could cause or contribute to such differences included, but are not limited to: (i) increased prices for fuel and purchased power, (ii) the possibility that regulators may not permit the Company to pass through all such increased costs to customers, (iii) fluctuations in wholesale margins due to uncertainty in the wholesale power market, (iv) unanticipated increased costs associated with scheduled and unscheduled outages, (v) the cost of replacing steam generators and other unexpected costs at Palo Verde and (vi) other factors discussed below under the headings “Summary of Critical Accounting Policies and Estimates,” “Overview” and “Liquidity and Capital Resources.” The Company’s filings are available from the Securities and Exchange Commission or may be obtained upon request from the Company. Any such forward-looking statement is qualified by reference to these risks and factors. The Company cautions that these risks and factors are not exclusive. The Company does not undertake to update any forward-looking statement that may be made from time to time by or on behalf of the Company except as required by law.
Summary of Critical Accounting Policies and Estimates
Note A to the Consolidated Financial Statements contains a summary of the significant accounting policies that the Company uses. The preparation of these statements requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and related notes for the periods presented and actual results could differ from those estimates. Critical accounting estimates, which are both important to the portrayal of the Company’s financial condition and results of operations and which require complex, subjective judgments, include the following:
·
Value of net utility plant in service
·
Decommissioning costs
·
Collection of fuel expense
·
Future pension and other postretirement obligations
·
Reserves for tax dispute
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 and New Mexico, the Company will no longer be permitted to recover in rates any “stranded costs”, that is, the difference between the book value and the market value of its electric generation assets. If at any time the Company determines that estimated, undiscounted future net cash flows from the operations of the generation assets are not sufficient to recover their net book value then it will be required to write down the value of these assets to their fair values. Any such writedown would be charged to earnings. The Company currently believes that its rates are sufficient to fully collect before 2005 all costs that would otherwise be “stranded” under relevant laws in Texas and New Mexico and that future net cash flows after 2005 from the generating assets will be sufficient to recover their net book values.
Decommissioning Costs
Pursuant to the ANPP Participant Agreement and federal law, the Company must fund its share of the estimated costs to decommission Palo Verde Units 1, 2, and 3 and associated common areas. The Company and other Palo Verde Participants rely upon decommissioning cost studies and make interest rate, rate of return and inflation projections to determine funding requirements and estimate liabilities related to decommissioning. Every third year, outside engineers perform a study to estimate decommissioning costs associated with Palo Verde Units 1, 2 and 3 and associated common areas. The Company funds its share of those estimated costs through professionally managed investment trust accounts. Management must make assumptions about future investment returns and future cost escalations in order to determine the amounts with which to fund the trusts. If actual decommissioning costs exceed estimates, the Company would incur additional expenses related to decommissioning. Further, if the rates of return earned by the trusts fail to meet expectations, the Company will be required to increase its funding to the decommissioning trust accounts. Although the Company cannot predict the results of future studies, the Company believes that the liability it has recorded for its decommissioning costs will be adequate to provide for the Company’s share of the costs. The Company believes that its current annual funding levels of the decommissioning trust will adequately provide for the cash requirements associated with decommissioning. Historically, regulated utilities such as the Company have been permitted to collect in rates the costs of nuclear decommissioning. Under deregulation legislation in both Texas and New Mexico, the Company expects to continue to be able to collect from customers the costs of decommissioning.
Collection of Fuel Expense
As a regulated entity, the Company’s fuel and purchased power expenses are passed through directly to its regulated customers. These costs are then subject to a prudency review of its fuel and purchased power costs by the Texas and New Mexico Commissions. In general, if the Texas and New Mexico Commissions find that the fuel and purchased power expenses were reasonably incurred, the Company may recover those expenses from its customers. Until those periodic reviews are completed, however, management must rely upon projections related to fuel and purchased power prices in order to estimate fuel revenues. When prices exceed management’s estimates, the Company undercollects fuel and purchased power expenses from its customers. The Company must then petition its regulators to reconcile its actual costs to actual revenues received from customers. Historically, regulators have allowed the Company to recover most of its fuel and purchased power-related expenses. If energy costs were deemed unreasonably incurred and regulators were to disallow recovery of these costs, however, the Company would incur a loss to the extent of the disallowance.
Future Pension and Other Postretirement Obligations
In accounting for its retirement plans and other postretirement benefits, the Company makes assumptions regarding the valuation of benefit obligations and the performance of plan assets. The accounting for retirement plans and other postretirement obligations allows for a smoothed recognition of changes in benefit obligations and plan performance over the service lives of the employees who benefit under the plans. The primary assumptions are discount rate, expected return on plan assets, rate of compensation increase and health care cost inflation. A change in any of these assumptions could have a significant impact on future costs, which may be reflected as an increase or decrease in net income in the period, or on the amount of related liabilities reflected on the Company’s consolidated balance sheet.
Reserves for Tax Dispute
The IRS has disputed whether the Company was entitled to deduct certain payments made in 1996 related to Palo Verde and its treatment of a litigation settlement in 1997 related to a terminated merger agreement. If the IRS prevails on the former issue, the Company would be required to include the previously deducted amounts in the tax basis of Palo Verde and deduct them over its useful life. This would not have a material impact on reported net income but would have a significant negative effect on the Company’s cash flow. An adverse resolution of the second issue would lead to the recognition of additional revenue in the Company’s tax return with no related tax benefits and could result in a material amount of additional tax. The Company has established, and periodically reviews and re-evaluates, an estimated contingent tax liability on its consolidated balance sheet to provide for the possibility of adverse outcomes in tax proceedings. Although the ultimate outcome cannot be predicted with certainty, and while the contingent tax reserve may not in fact be sufficient, the Company believes that the amount at December 31, 2001 adequately provides for any additional tax that may be due.
Overview
El Paso Electric Company is an electric utility that serves retail customers in west Texas and southern New Mexico and wholesale customers in Texas, New Mexico, California and Mexico. The Company owns or has substantial ownership interests in six electrical generating facilities providing it with a total capacity of approximately 1,500 MW. The Company’s energy sources consist of nuclear fuel, natural gas, coal, purchased power and wind. The Company owns or has significant ownership interests in four major 345 kV transmission lines and three 500 kV lines to provide power from Palo Verde and Four Corners, and owns the distribution network within its retail service territory. The Company is subject to extensive regulation by the Texas and New Mexico Commissions and, with respect to wholesale power sales, transmission of electric power and the issuance of securities, by the FERC.
The Company faces a number of risks and challenges that could negatively impact its operations and financial results. The most significant of these risks and challenges arise from the deregulation of the electric utility industry, the possibility of increased costs, especially from Palo Verde, and the Company’s high level of debt.
The electric utility industry in general and the Company in particular are facing significant challenges and increased competition as a result of changes in federal provisions relating to third-party transmission services and independent power production, as well as changes in state laws and regulatory
provisions relating to wholesale and retail service. In 1999, both Texas and New Mexico passed industry deregulation legislation requiring the Company to separate its transmission and distribution functions, which will remain regulated, from its power generation and energy services businesses, which will operate in a competitive market in the future. New Mexico subsequently amended its deregulation law to delay the implementation date. While the Company is not subject to deregulation in its Texas and New Mexico jurisdictions until 2005 and 2007, respectively, the potential effects of competition in the power generation and energy services markets remain important to the Company. There can be no assurance that the deregulation of the power generation market will not adversely affect the future operations, cash flows and financial condition of the Company.
The changing regulatory environment and the advent of unregulated power production have created a substantial risk that the Company will lose important customers. The Company’s wholesale and large retail customers already have, in varying degrees, additional alternate sources of economical power, including co-generation of electric power. Historically, the Company has lost certain large retail customers to self generation and/or co-generation and seen reductions in wholesale sales due to new sources of generation. American National Power, Inc., a wholly-owned subsidiary of International Power PLC, has announced it is exploring the possibility of building a generation plant in El Paso, Texas. Duke Energy has begun the initial phase of construction on a generation plant in Deming, New Mexico and has announced it is exploring the possibility of building a generation plant in Lordsburg, New Mexico. Public Service Company of New Mexico has begun the construction of a generation plant outside Las Cruces, New Mexico. If the Company loses a significant portion of its retail customer base or wholesale sales, the Company may not be able to replace such revenues through either the addition of new customers or an increase in rates to remaining customers.
Another risk to the Company is potential increased costs, including the risk of additional or unanticipated costs at Palo Verde resulting from (i) increases in operation and maintenance expenses; (ii) the replacement of steam generators; (iii) an extended outage of any of the Palo Verde units; (iv) increases in estimates of decommissioning costs; (v) the storage of radioactive waste, including spent nuclear fuel; (vi) insolvency of other Palo Verde Participants and (vii) compliance with the various requirements and regulations governing commercial nuclear generating stations. At the same time, the Company’s retail base rates in Texas are effectively capped through a rate freeze ending in August 2005. Additionally, upon initiation of competition, there will be competitive pressure on the Company’s power generation rates which could reduce its profitability. The Company also 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.
Under the Texas Commission rules and the Company’s energy cost recovery clauses (“fuel clauses”) in certain wholesale rates, energy costs are passed through to customers. However, energy costs were not passed through to the Company’s New Mexico customers prior to June 15, 2001. These energy costs were included in base rates and were not subject to periodic reconciliation or adjustment for fluctuations in such costs. From January 1, 2001 through June 15, 2001, the Company incurred increased energy expenses which were not recoverable from New Mexico and certain wholesale customers of approximately $3.1 million, net of tax, compared to the year ended December 31, 2000. The New Mexico Commission allowed the Company to implement its New Mexico Fuel Factor Agreement, beginning with consumption on June 15, 2001, subject to refund. The New Mexico Commission granted final approval on January 8, 2002. The reinstatement of a fuel adjustment clause substantially mitigates the financial risk to the Company of any further energy cost increases over the
two-year period of the agreement. See Part I, Item 1, “Business - Regulation - New Mexico Regulatory Matters - Fuel” and Item 7A, “Quantitative and Qualitative Disclosures About Market Risk - Commodity Price Risk.”
As of December 31, 2001, the Company had an immaterial outstanding net receivable of approximately $0.2 million from Enron related to prepetition claims for which the Company has provided an allowance in its general allowance for bad debts. The Company is party to a power purchase contract with Enron requiring deliveries of electricity to the Company during 2002. If Enron fails to perform under this contract, the Company believes that it will be able to obtain replacement power at prices lower than those payable to Enron under the contract.
Liquidity and Capital Resources
The Company’s principal liquidity requirements in the near-term are expected to consist of interest and principal payments on the Company’s indebtedness and capital expenditures related to the Company’s generating facilities and transmission and distribution systems. The Company expects that cash flows from operations will be sufficient for such purposes.
Long-term capital requirements of the Company will consist primarily of construction of electric utility plant and payment of interest on and retirement of debt. Utility construction expenditures will consist primarily of expanding and updating the transmission and distribution systems, possible addition of new generation, and the cost of capital improvements and replacements at Palo Verde and other generating facilities, including the replacement of the Palo Verde steam generators. See Part I, Item 1, “Business - Construction Program.”
During 2001, 2000 and 1999, the Company utilized $128.0 million, $93.6 million and $97.8 million, respectively, of federal tax loss carryforwards. The Company anticipates that existing federal tax loss carryforwards will be fully utilized in 2003 and after that date the Company’s cash flow requirements are expected to include greater amounts of cash paid for income taxes than has existed in recent years.
At December 31, 2001, the Company had approximately $28.0 million in cash and cash equivalents, an increase of $16.7 million from the December 31, 2000 balance of $11.3 million. The Company also has a $100 million revolving credit facility, which provides up to $70 million for nuclear fuel purchases. Any amounts not borrowed for nuclear fuel purchases may be borrowed by the Company for working capital needs. In January 2002, the revolving credit facility was renewed for a three-year term. At December 31, 2001, approximately $48.3 million had been drawn for nuclear fuel purchases. No amounts are currently outstanding on this facility for working capital needs.
The Company has a high debt to capitalization ratio and significant debt service obligations. Due to the Texas Rate Stipulation, the Texas Settlement Agreement, and competitive pressures, the Company does not expect to be able to raise its base rates in Texas in the event of increases in non-fuel costs or loss of revenues. See Part I, Item 1, “Business - Regulation - Texas Regulatory Matters.” Accordingly, as described below, debt reduction continues to be a high priority for the Company in order to gain additional financial flexibility to address the evolving competitive market.
The Company has significantly reduced its long-term debt since its emergence from bankruptcy in 1996. From June 1, 1996 through March 11, 2002, the Company repurchased approximately $431.3 million of first mortgage bonds with internally generated cash as part of a deleveraging program
and repaid the remaining $36.0 million and $34.6 million of Series A and Series B First Mortgage Bonds at their maturity in February 1999 and May 2001, respectively, which has combined to reduce the Company’s annual interest expense by approximately $40.6 million. The Company also redeemed its 11.40% Series A Preferred Stock in March 1999, which resulted in the avoidance of approximately $15.9 million in annual cash dividends that would have been payable until mandatory redemption in 2008. Common stock equity as a percentage of capitalization, including current maturities of long-term debt, has increased from 19% at June 30, 1996 to 39% at December 31, 2001. In addition, the Company’s bonds are rated investment grade by all three major credit rating agencies.
The Company continues to believe that the orderly reduction of debt with a goal of achieving a capital structure that is more typical in the electric utility industry is a significant component of long-term shareholder value creation. Accordingly, the Company will regularly evaluate market conditions and, when appropriate, use a portion of its available cash to reduce its fixed obligations through open market purchases of first mortgage bonds.
The degree to which the Company is leveraged could have important consequences on the Company’s liquidity, including (i) the Company’s ability to obtain additional financing for working capital, capital expenditures, acquisitions, general corporate or other purposes could be limited in the future and (ii) the Company’s higher than average leverage may place the Company at a competitive disadvantage by limiting its financial flexibility to respond to the demands of the competitive market and make it more vulnerable to adverse economic or business changes.
The Company’s Board of Directors previously approved two stock repurchase programs allowing the Company to purchase up to twelve million of its outstanding shares of common stock. On February 7, 2002, the Company’s Board of Directors approved a third stock repurchase program allowing the Company to purchase up to three million shares of common stock. As of March 11, 2002, the Company had repurchased 11,921,329 shares of common stock under these programs for approximately $133.9 million, including commissions. The Company expects to continue to make purchases primarily in the open market at prevailing prices and will also engage in private transactions, if appropriate. Any repurchased shares will be available for issuance under employee benefit and stock option plans, or may be retired.
Historical Results of Operations
Electric utility operating revenues net of energy expenses increased $7.8 million in 2001 compared to 2000 and $17.1 million in 2000 compared to 1999, primarily due to changes in the following (in thousands):
(1)
A sales tax refund of $1.8 million was received in 2000 and based on a related negotiated settlement in 2001, $1.2 million was credited to the Texas jurisdictional customers through the fuel adjustment clause.
(2)
Represents an adjustment in December 1999 reducing fuel expense based on a reduction of the Company’s estimated coal mine reclamation liability.
Comparisons of kWh sales and electric utility operating revenues are shown below (in thousands):
(1)
Primarily due to increased kWh sales to CFE and IID.
(2)
Primarily due to a weaker power market in the last half of 2001.
(3)
Primarily due to increased energy expenses that are passed through directly to Texas and New Mexico (beginning June 15, 2001) jurisdictional customers.
(4)
Primarily due to (i) increased energy expenses that are passed through directly to certain wholesale customers and (ii) increased sales to CFE.
(5)
Primarily due to (i) increased margins on economy sales and (ii) higher average prices as a result of increased energy expenses. These increases were partially offset by decreased kWh sales.
(6)
Represents revenues with no related kWh sales.
(7)
2000 includes margins on energy swaps of $4.3 million with no comparable activity in 2001. In early 2000, the Company entered into several power purchase contracts for the summer months to ensure there would be sufficient power available to meet increased customer demand. For at least two of these contracts, the Company agreed to pay market-based index prices rather than fixed prices. As power prices began to escalate in the second quarter of 2000, the Company entered into two financial swap agreements in which the Company agreed to pay fixed prices and the counterparty agreed to pay market-based prices for the notional amounts of kWh in the swap agreements. Market prices continued to escalate over the summer of 2000 and, under the swap agreement, the Company received the difference between the fixed prices and the higher market index prices on the notional kWh amounts.
(8)
Primarily due to (i) increased kWh sales to IID and (ii) sales to CFE as a result of a contract that was effective from June through August 2000 with no comparable sales to CFE in 1999.
(9)
In order to ensure sufficient availability of purchased power during the summer of 2000, the Company entered into a firm purchased power contract in January 2000 that was effective through the end of the year. The increase in economy kWh sales is primarily due to the sale of power purchased under this contract that was not needed to serve native load and wholesale contracts during the non-summer
months. The increase in economy sales revenue was primarily due to (i) increased margins, (ii) increased prices as a result of increased energy expenses and (iii) increased kWh sales.
(10)
Includes the effects of the Texas Settlement Agreement and change in estimated fuel cost reserves of $4.9 million.
(11)
Primarily due to (i) increased energy expenses that are passed through directly to Texas jurisdictional customers and (ii) increased kWh sales.
(12)
Primarily due to energy swaps described in (7) above.
Other electric utility operations and maintenance expense increased $8.5 million and $7.2 million in 2001 compared to 2000 and in 2000 compared to 1999, respectively, as follows (in thousands):
(1)
Primarily due to scheduled maintenance outages in 2001.
(2)
Primarily due to an increase in OPEB costs resulting from a change in discount rate and escalation assumptions for medical costs for 2001.
(3)
Primarily due to a decrease in consulting fees and corporate restructuring expenses.
(4)
Primarily due to (i) an insurance claim receivable recognized in 1999 for expenses of a major overhaul of gas turbines at a local plant that were recognized in prior periods and (ii) unscheduled maintenance due to a mechanical problem with a turbine shaft in 2000.
(5)
Primarily due to increased expenses for (i) a one-time environmental assessment of $0.3 million spent to perform a storm water study at Company-owned generating plants and (ii) new maintenance agreements on computer equipment.
(6)
Primarily due to (i) the 1999 reversal of a receivable related to anticipated refunds on medical payments and (ii) increased medical expenses in 1999 with no comparable activity in 2000.
Depreciation and amortization expense increased $0.8 million in 2001 compared to 2000 primarily due to an increase in depreciable plant balances. The decrease of $4.0 million in 2000 compared to 1999 was primarily due to a change in the estimated depreciable life of the plant investment related to the decommissioning of Palo Verde from 10 to 27.25 years, based on the license expiration date of Unit 3. The Texas Restructuring Law permitted recovery of nuclear decommissioning costs over the service lives of the relevant nuclear plants. Depreciation rates for the
Texas jurisdictional portion of the plant investment ($59 million) were adjusted to reflect the increased service life. The New Mexico jurisdictional portion of the plant investment ($17 million) continues to be depreciated over 10 years. This shorter service life is based on the uncertainty of recovering all decommissioning costs under the New Mexico restructuring legislation. For all other utility plants, Texas and New Mexico depreciation lives are the same.
Taxes other than income taxes remained relatively unchanged in 2001 compared to 2000. Taxes other than income taxes increased $1.7 million in 2000 compared to 1999 primarily due to (i) a $3.1 million reversal in 1999 of sales tax reserves established in prior years with no comparable amount in 2000 and (ii) an increase in Texas revenue related to taxes due to higher operating income in 2000. These increases were partially offset by a $1.7 million decrease in Arizona property taxes as a result of depreciation and a regulatory basis plant write-down pursuant to the New Mexico Settlement Agreement.
Other income (deductions) decreased $0.3 million in 2001 compared to 2000 primarily due to a decrease of $2.4 million of investment income related to the decommissioning trust fund and the IID contract receivable. These decreases were partially offset by an increase of $1.6 million in interest income on the undercollection of Texas fuel revenues and a $0.5 million insurance reimbursement recognized in 2001 for a loss expensed in a prior period. The increase of $8.0 million in 2000 compared to 1999 was primarily due to the accrual in 1999 of $16.5 million to be paid under the settlement agreement with Las Cruces. This increase was partially offset by (i) a decrease in investment income of $3.4 million resulting from the investment of lower levels of cash; (ii) a 1999 adjustment of $1.7 million to the cash value of Company-owned life insurance policies and (iii) a gain realized on the disposition of non-utility property of $2.4 million in 1999 with no comparable activity in 2000.
Interest charges decreased $4.9 million in 2001 compared to 2000 primarily due to (i) a reduction in outstanding debt as a result of open market purchases of the Company’s first mortgage bonds; (ii) increased capitalized interest related to construction work in progress and (iii) decreased interest rates. These decreases were partially offset by an increase of $1.6 million in interest expense resulting from the remarketing of the pollution control bonds. The decrease of $10.0 million in 2000 compared to 1999 was primarily due to (i) a reduction in outstanding debt as a result of open market purchases of the Company’s first mortgage bonds and (ii) adjustments to postload nuclear fuel to write-off a portion of accumulated interest capitalized prior to 1999 and discontinue capitalizing interest thereon in 1999.
Income tax expense, excluding the tax effect of extraordinary items, decreased $2.5 million in 2001 compared to 2000 primarily due to changes in pretax income and certain permanent differences and adjustments including (i) a reduction to the Company’s estimated contingent federal tax liabilities based upon discussions and agreed issues with taxing authorities related to the IRS examination of the Company’s 1996 through 1998 tax returns and (ii) deductions taken for abandoned transition costs. The increase of $13.3 million in 2000 compared to 1999 was primarily due to changes in pretax income and certain permanent differences including (i) an increase in nondeductible transition costs; (ii) a decrease in the adjustment to the cash value of Company-owned life insurance policies and (iii) a decrease in tax-exempt income.
Extraordinary loss on extinguishments of debt, net of income tax benefit, represents the payment of premiums on debt extinguishments and the recognition of unamortized issuance expenses on that debt.
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.
In July 2001, the Financial Accounting Standards Board (the “FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No. 141, “Business Combinations” and SFAS No. 142, “Goodwill and Other Intangible Assets.” The Company does not believe that its activities or assets as of December 31, 2001 will be impacted by these standards.
Additionally, in July 2001, the FASB issued SFAS No. 143, “Accounting for Asset Retirement Obligations” (“SFAS No. 143”). SFAS No. 143 provides accounting guidance for retirement obligations, for which there is a legal obligation to settle, associated with tangible long-lived assets. SFAS No. 143 requires that asset retirement costs be capitalized as part of the cost of the related long-lived asset and such costs should be allocated to expense by using a systematic and rational method. SFAS No. 143 requires the initial measurement of the asset retirement obligation liability to be recorded at fair value and the use of an allocation approach for subsequent changes in the measurement of the liability. Upon adoption of SFAS No. 143, an entity will use a cumulative-effect adjustment to recognize transition amounts for any existing asset retirement obligation liability, asset retirement costs and accumulated depreciation. SFAS No. 143 is effective for fiscal years beginning after June 15, 2002. Management has not yet quantified the impact of adopting SFAS No. 143 on the Company’s financial statements.
On October 3, 2001, the FASB issued SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” (“SFAS No. 144”). While SFAS No. 144 supersedes SFAS No. 121, “Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of,” it retains many of the fundamental provisions of that standard. SFAS No. 144 is effective for fiscal years beginning after December 15, 2001. The Company does not believe that its assets as of December 31, 2001, will be impacted by this standard.
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 and the Company’s energy cost recovery clauses (“fuel clauses”) in certain wholesale rates. Under these rules and fuel clauses, energy costs, including interest expense on nuclear fuel financing, are passed through to customers. Currently, the Company does not have a plan to issue additional long-term debt within the
next five years, although it anticipates remarketing its pollution control bonds, a portion in 2002 and a portion in 2005.
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 $26.0 million and $27.6 million as of December 31, 2001 and 2000, respectively. A hypothetical 10% increase in interest rates would reduce the fair values of these funds by $0.5 million and $0.6 million based on their fair values at December 31, 2001 and 2000, respectively.
Equity Price Risk
The Company’s decommissioning trust funds include marketable equity securities of approximately $34.9 million and $32.6 million at December 31, 2001 and 2000, respectively. A hypothetical 20% decrease in equity prices would reduce the fair values of these funds by $7.0 million and $6.5 million based on their fair values at December 31, 2001 and 2000, 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 fixed and 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, 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.
Natural gas and purchased power prices increased significantly from May 2000 through May 2001. Prior to July 2001, energy costs were included in frozen base rates for New Mexico and certain wholesale customers. During the first half of 2001, the Company’s average energy costs incurred for, but not recovered from, these customers substantially exceeded the energy costs that were incorporated into the applicable base rates. See Part I, Item 1, “Business - Regulation - New Mexico Regulatory Matters - Fuel” for further discussion. However, the Company has since entered into the New Mexico Fuel Factor Agreement, which allows the Company to pass energy costs through to its New Mexico customers. The implementation of the provisions of the agreement substantially mitigated the remaining financial risk to the Company of any further energy cost increases.
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 March 11, 2002, 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 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.
Item 8.
Item 8. Financial Statements and Supplementary Data
Page
Independent Auditors’ Report
Consolidated Balance Sheets at December 31, 2001 and 2000
Consolidated Statements of Operations for the years ended December 31, 2001, 2000 and 1999
Consolidated Statements of Comprehensive Operations for the years ended December 31, 2001, 2000 and 1999
Consolidated Statements of Changes in Common Stock Equity for the years ended December 31, 2001, 2000 and 1999
Consolidated Statements of Cash Flows for the years ended December 31, 2001, 2000 and 1999
Notes to Consolidated Financial Statements
INDEPENDENT AUDITORS’ REPORT
The Shareholders and Board of Directors
El Paso Electric Company
We have audited the accompanying consolidated balance sheets of El Paso Electric Company and subsidiary as of December 31, 2001 and 2000, and the related consolidated statements of operations, comprehensive operations, changes in common stock equity and cash flows for the years ended December 31, 2001, 2000 and 1999. 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 auditing standards generally accepted in the United States of America. 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, 2001 and 2000, and the results of their operations and their cash flows for the years ended December 31, 2001, 2000 and 1999, in conformity with accounting principles generally accepted in the United States of America.
KPMG LLP
El Paso, Texas
March 11, 2002
EL PASO ELECTRIC COMPANY AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
See accompanying notes to consolidated financial statements.
EL PASO ELECTRIC COMPANY AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS (Continued)
See accompanying notes to consolidated 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.
EL PASO ELECTRIC COMPANY AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF COMPREHENSIVE OPERATIONS
(In thousands)
See accompanying notes to consolidated 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.
EL PASO ELECTRIC COMPANY AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
See accompanying notes to consolidated 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, New Mexico, California and 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, provides energy efficiency products and services previously provided by the Company’s Energy Services Business Group. All intercompany transactions and balances have been eliminated in consolidation. Additionally, the revenues and expenses of the former Energy Services Business Group have been reclassified for all periods presented in the accompanying consolidated statements of operations as energy services revenues and expenses.
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”). The Company determined that it does not meet the criteria for the application of Statement of Financial Accounting Standards (“SFAS”) No. 71, “Accounting for the Effects of Certain Types of Regulation,” and accordingly does not report the effects of certain actions of regulators as assets or liabilities unless such actions result in assets or liabilities under generally accepted accounting principles for commercial enterprises in general.
Comprehensive Income. Certain gains and losses that are not recognized currently in the 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 over the ten-year period of a rate settlement (the “Texas Rate Stipulation”). Based on a provision in the Texas Restructuring Law allowing recovery of nuclear decommissioning costs over the service lives of nuclear plants, as of January 1, 2000, the Company changed the estimated useful life of the plant investment of approximately $59 million for the Texas jurisdiction related to the decommissioning of Palo Verde. Previously, this decommissioning portion of Palo Verde plant costs had been depreciated over 10 years. As a result, the Company changed the depreciation life of the Texas jurisdictional portion of its decommissioning of Palo Verde from 10 years to 27.25 years, the remaining
EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
service life of Palo Verde based on the license expiration date of Unit 3. The remaining portion of the plant investment related to the decommissioning of Palo Verde continues to be depreciated over 10 years. For all other utility plant, Texas and New Mexico depreciation lives are the same. 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 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 retirements or other dispositions of operating property in the normal course of business are credited or charged to the accumulated provision for depreciation.
The Company recorded a liability for its interest in Palo Verde equal to the present value of the Company’s portion of total estimated decommissioning costs using a cost inflation rate of 3% and a discount rate of 6%. Accretion of the decommissioning liability is charged to other interest charges in the statements of operations. Changes in the decommissioning liability arising from changes in the timing or amount of estimated total decommissioning costs are capitalized to utility plant.
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 expensing its share of costs, as incurred, associated with on-site spent fuel storage at Palo Verde. See Note C.
Impairment of Long-Lived Assets. The Company evaluates impairment of its long-lived assets and certain intangible assets whenever events or changes in circumstances indicate that the carrying amount of the asset may not be recoverable. An asset is deemed impaired if the sum of the expected future cash flows is less than the carrying amount 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.”
Cash and Cash Equivalents. All temporary cash investments with an original maturity of three months or less are considered cash equivalents.
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.
EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Inventories. Inventories, primarily parts, materials, supplies and fuel oil are stated at average cost not to exceed recoverable cost.
Electric Utility 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 and New Mexico (as of June 2001) retail customers are presently being billed under a fixed fuel factor approved by the state commissions. 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. Rate tariffs currently applicable to certain FERC jurisdictional customers contain energy cost adjustment provisions designed to recover the Company’s actual energy expenses. The difference between energy expenses incurred and fuel revenues charged to the Company’s Texas, New Mexico and applicable FERC jurisdictional customers, as determined under Texas and New Mexico Commission rules and FERC rate tariffs, is reflected as net over/undercollection of fuel revenues in the balance sheets.
Allowance for Doubtful Accounts. Additions, deductions and balances for allowance for doubtful accounts for 2001, 2000 and 1999 are as follows (in thousands):
(1)
Recovery of amounts previously written off.
(2)
Uncollectible receivables written off.
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 bases 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 common share is computed by dividing net income, after deducting the preferred stock dividend requirements, by the weighted average number of common shares outstanding. Diluted earnings per common share is computed by dividing net income, after deducting the preferred stock dividend requirements, by the weighted average number of common shares and dilutive potential common shares outstanding.
EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Benefit Plans. See Note J for accounting policies regarding the Company’s retirement plans and postretirement benefits.
Stock Options and Restricted Stock. The Company has a long-term incentive plan which reserves shares of common stock for issuance to officers, key employees and non-employee directors through the award or grant of stock options and restricted stock. The Company has adopted the disclosure-only provisions of SFAS No. 123, “Accounting for Stock-Based Compensation” (“SFAS No. 123”). Accordingly, compensation expense is recognized for the intrinsic value, if any, of option grants at measurement date ratably over the vesting period of the options. Compensation expense for the restricted stock awards is recognized for the fair value as measured by the quoted market price of the shares at the award date ratably over the restriction period. Unearned compensation related to restricted stock awards is shown as a reduction of common stock equity.
Reclassification. Certain amounts in the financial statements for 2000 and 1999 have been reclassified to conform with the 2001 presentation.
Supplemental Statements of Cash Flows Disclosures (in thousands)
B. Regulation
General
In 1999, both Texas and New Mexico enacted electric utility industry restructuring laws requiring competition in certain functions of the industry and ultimately in the Company’s service area.
EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Competition in New Mexico was scheduled to begin on January 1, 2002 under the New Mexico Restructuring Law. On March 8, 2001, however, the New Mexico Restructuring Law was amended to delay the start of competition for five years until January 1, 2007. Under the Texas Restructuring Law, the Company’s Texas service area is exempt from competition until the expiration of the Freeze Period in August 2005.
The Company continues to work to become more competitive in response to these restructuring laws and to other regulatory, economic and technological changes occurring throughout the industry. Deregulation of the production of electricity and related services and increasing customer demand for lower priced electricity and other energy services have accelerated the industry’s movement toward more competitive pricing and cost structures. Those competitive pressures could result in the loss of customers and diminish the ability of the Company to fully recover its investment in generation assets. In January 2002, competition was initiated in most parts of Texas. As a result, the Company may face increasing pressure on its retail rates and its rate freeze under the Texas Rate Stipulation. The Company’s results of operations and cash flows may be adversely affected if it cannot maintain its current retail rates.
Texas Regulatory Matters
The rates and services of the Company in Texas municipalities are regulated by those municipalities and in unincorporated areas by the Texas Commission. The largest municipality in the Company’s service area is the City of El Paso. The Texas Commission has exclusive appellate jurisdiction to review municipal orders and ordinances regarding rates and services in Texas and jurisdiction over certain other activities of the Company. The decisions of the Texas Commission are subject to judicial review.
Deregulation. The Texas Restructuring Law requires an electric utility to separate its power generation activities from its transmission and distribution activities by January 1, 2002. In January 2002, competition was instituted in most parts of Texas. Nonetheless, the Texas Restructuring Law specifically recognizes and preserves the substantial benefits the Company bargained for in its Texas Rate Stipulation and Texas Settlement Agreement, exempting the Company’s Texas service area from retail competition, and preserving rates at their current levels until the end of the Freeze Period. At the end of the Freeze Period, the Company will be subject to retail competition and at that time will be permitted to recover nuclear decommissioning costs in rates, but will have no further claim for recovery of stranded costs. Stated simply, stranded costs are the positive difference, if any, between the book value of electric generating assets, including long-term purchase power contracts, and the market value of those assets.
Although the Company is not subject to the Texas restructuring requirements until the expiration of the Freeze Period, the Company sought Texas Commission approval of the Company’s corporate restructuring in anticipation of complying with the restructuring requirements of the New Mexico Restructuring Law. In December 2000, the Texas Commission approved the Company’s corporate restructuring plan. However, the amended New Mexico Restructuring Law now prohibits the separation of the Company’s generation activities from its transmission and distribution activities before September 1, 2005, directly conflicting with the Texas Restructuring Law requiring separation of these
EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
activities after expiration of the Freeze Period in August 2005. Accordingly, in either 2004 or 2005, the Company will seek New Mexico Commission approval to separate the Company’s generation activities from its transmission and distribution activities to allow the Company to comply with the Texas Restructuring Law requirements.
Texas Rate Stipulation and Texas Settlement Agreement. The Texas Rate Stipulation and Texas Settlement Agreement govern the Company’s rates for its Texas customers, but do not deprive the Texas regulatory authorities of their jurisdiction over the Company during the Freeze Period. However, the Texas Commission determined that the rate freeze is in the public interest and results in just and reasonable rates. Further, the signatories to the Texas Rate Stipulation (other than the Texas Office of Public Utility Counsel and the State of Texas) agreed not to seek to initiate an inquiry into the reasonableness of the Company’s rates during the Freeze Period and to support the Company’s entitlement to rates at the freeze level throughout the Freeze Period. The Company believes, but cannot assure, that its cost of service will support rates at or above the freeze level throughout the Freeze Period and, therefore, does not believe any attempt to reduce the Company’s rates would be successful. However, during the Freeze Period, the Company is precluded from seeking base rate increases in Texas, even in the event of increased operating or capital costs. In the event of a merger, the parties to the Texas Rate Stipulation retain all rights provided in the Texas Rate Stipulation, the right to participate as a party in any proceeding related to the merger, and the right to pursue a reduction in rates below the freeze level to the extent of post-merger synergy savings.
Fuel. Although the Company’s base rates are frozen in Texas, pursuant to Texas Commission rules and the Texas Rate Stipulation, the Company can request adjustments to its fuel factor to more accurately reflect projected energy costs associated with the provision of electricity as well as seek recovery of past undercollections of fuel revenues.
In October 2001, the Texas Commission approved a unanimous settlement agreement (the “Texas Fuel Settlement”) between the Company and the parties which had intervened, including the City of El Paso, which increased the Texas fuel factor to $0.02494 per kWh. This factor was implemented on an interim basis in April 2001 and increased fuel revenue collections by $11.7 million for the year ended December 31, 2001. The Texas Fuel Settlement also provides for the surcharge of underrecovered fuel costs as of December 31, 2000 of approximately $15 million plus interest over an 18-month period. The fuel surcharge was implemented on an interim basis beginning with the first billing cycle in June 2001. The Texas Fuel Settlement provides for the final agreement between the parties for the non-recovery of certain purchased power contract costs as well as the favorable disposition of previously unrecognized Palo Verde performance rewards, including interest. These provisions taken together did not have a material effect on the Company’s results of operations and resulted in an $11.0 million increase in Net Undercollection of Fuel Revenues and a $10.5 million increase in Deferred Credits and Other Liabilities - Other, which were recorded in June 2001. The Company also agreed to a prospective change in the Palo Verde performance standards, which materially reduced the potential for future rewards and penalties on a symmetrical basis.
The Company anticipates terminating its interim fuel surcharge earlier than expected and anticipates filing a petition with the Texas Commission in April 2002 to end that surcharge of
EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
underrecovered fuel costs. The interim fuel surcharge, as well as the Company’s other energy expenses through year-end 2001, will be subject to final review by the Texas Commission in the Company’s next fuel reconciliation proceeding, which is expected to be filed in June 2002. The Texas Commission staff, local regulatory authorities such as the City of El Paso, and customers are entitled to intervene in a fuel reconciliation proceeding and to challenge the prudence of fuel and purchased power expenses.
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. As mentioned above these performance standards were materially altered during 2001. 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. The Company has calculated approximately $1 million of performance rewards for the 2001 reporting period. These rewards will be included, along with energy costs incurred, as part of the Texas Commission’s review during the periodic fuel reconciliation proceedings discussed above. Those performance rewards will not be recorded on the Company’s books until the Texas Commission has ordered a final determination in a fuel reconciliation proceeding. Performance penalties are recorded when assessed as probable by the Company.
New Mexico Regulatory Matters
The New Mexico Commission has jurisdiction over the Company’s rates and services in New Mexico and over certain other activities of the Company, including prior approval of the issuance, assumption or guarantee of securities. The New Mexico Commission’s decisions are subject to judicial review. The largest city in the Company’s New Mexico service territory is Las Cruces.
Deregulation. In March 2001, the New Mexico Legislature amended the New Mexico Restructuring Law to postpone deregulation in New Mexico until January 1, 2007, and to prohibit the separation of a utility’s transmission and distribution activities from its existing generation activities prior to September 1, 2005. The amended New Mexico Restructuring Law permits utilities to form holding companies subject to New Mexico approval with conditions. It also allows the utility, until corporate separation occurs, to participate in unregulated generation activities if the generation is not intended to serve New Mexico retail customers.
The amended New Mexico Restructuring Law prohibiting the separation of the Company’s generation activities from its transmission and distribution activities prior to September 1, 2005 may conflict with the Texas Restructuring Law requiring separation of those activities after the expiration of the Freeze Period in August 2005. Accordingly, the Company is currently evaluating possible benefits, if any, of forming a holding company prior to 2005. The Company anticipates that it will seek New Mexico Commission approval to separate the Company’s generation activities from its transmission
EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
and distribution activities in either 2004 or 2005 to allow the Company to restructure at the earliest time allowable.
The amended New Mexico law required the New Mexico Commission to approve previously filed applications to form holding companies to the extent that the applications do not conflict with the provisions of the law as amended and are otherwise in the public interest. Accordingly, in early April 2001, the Company filed its suggested amendments to its previously filed proposed corporate restructuring plan. The filing sought to conform the Company’s proposal with the requirements under the amended law which requires the regulated utility to continue to own all regulated generation currently owned and operated by the utility. On June 28, 2001, the New Mexico Commission issued its order approving formation of a holding company for the Company, but also placing thirty-eight conditions upon its approval. The conditions included numerous reporting and compliance requirements as well as strict prohibitions on certain intercompany activity. The Company sought rehearing on the order, which was denied without action by the Commission. The Company filed an appeal with the New Mexico Supreme Court on September 15, 2001. After reviewing the Company’s options in light of the Commission’s holding company order, the Company determined it was in its best interest to withdraw its request for a holding company and request that the Commission vacate the order. The Company, the New Mexico Commission and the Attorney General filed a joint motion asking the Court to dismiss the appeal so the Commission could vacate the order and allow the Company to withdraw its application. The Court dismissed the appeal on October 10, 2001, and the Commission vacated the order on December 18, 2001. Thus, the Company is no longer subject to the holding company conditions. The Company may request approval of a holding company at a later date, if and when needed, subject to whatever legal requirements are in effect at that time.
The New Mexico Restructuring Law allows the Company to recover reasonable, prudent and unmitigated costs that the Company would not have incurred but for its compliance with the New Mexico Restructuring Law. The March 2001 amendment to the New Mexico Restructuring Law did not address the recovery of transition costs spent to date. The Company cannot predict whether and to what extent the New Mexico Commission will allow the Company to recover these transition costs during the five year delay. Such costs, to the extent they are not capitalizable as fixed assets, are expensed as incurred.
Fuel. The New Mexico Settlement Agreement entered into in October 1998 eliminated the then existing fuel factor of $0.01949 per kWh incorporating it into frozen base rates. Accordingly, the Company was required to absorb any increases in fuel and purchased power (“energy”) expenses related to its New Mexico retail customers until new rates were implemented subsequent to the end of the rate freeze on April 30, 2001. The average energy costs incurred for New Mexico jurisdictional customers exceeded this fuel factor by a substantial amount. Therefore, on April 23, 2001, the Company filed a petition with the New Mexico Commission proposing a settlement that would implement a new fixed fuel factor and reinstate for a two-year period a fuel adjustment clause in lieu of a base rate increase (the “New Mexico Fuel Factor Agreement”). The New Mexico Commission allowed the Company to implement its New Mexico Fuel Factor Agreement on an interim basis, beginning on June 15, 2001, subject to final approval of the New Mexico Commission. The New Mexico Commission entered its final order on January 8, 2002, setting a fixed fuel factor of $0.01501 per kWh.
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Due to the decrease in gas prices since mid-2001, on February 12, 2002, the Company filed a petition with the New Mexico Commission for a fuel factor decrease to $0.00420 per kWh. The New Mexico Commission issued an order approving that decrease on February 19, 2002.
Federal Regulatory Matters
Federal Energy Regulatory Commission. The Company is subject to regulation by the FERC in certain matters, including rates for wholesale power sales, transmission of electric power and the issuance of securities.
Fuel. Under FERC regulations, the Company’s fuel factor is adjusted monthly for almost all FERC jurisdictional customers. Accordingly, any increase or decrease in energy expenses immediately flows through to such customers.
RTOs. On December 15, 1999, the FERC approved its final rule (“Order 2000”) on Regional Transmission Organizations (“RTOs”). Order 2000 strongly encourages, but does not require, public utilities to form and join RTOs. Order 2000 also proposes RTO startup by December 15, 2001. The Company is an active participant in the development of WestConnect, formerly known as the Desert Southwest Transmission and Reliability Operator. The Company believes WestConnect will qualify as an RTO under Order 2000. The Company intends, subject to the resolution of outstanding issues, to participate in WestConnect. As a participating transmission owner, the Company will transfer operations of its transmission system to WestConnect. The WestConnect proposal was submitted to the FERC on October 15, 2000. On March 1, 2001, the WestConnect proposal was updated to inform the FERC that the start of WestConnect operations would be delayed. WestConnect currently is scheduled to become operational by January 1, 2003. If WestConnect should fail to become operational, the Company would seek to participate in another RTO similar to WestConnect.
Department of Energy. The DOE regulates the Company’s exports of power to Comision Federal de Electricidad de Mexico (“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 Note C for discussion of spent fuel storage and disposal costs.
Nuclear Regulatory Commission. The Nuclear Regulatory Commission (“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.
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Sales for Resale
During 2001, the Company provided Imperial Irrigation District (“IID”) with 100 MW of firm capacity and associated energy and 50 MW of system contingent capacity and associated energy pursuant to a 17-year agreement which expires on April 30, 2002. The Company also provided Texas-New Mexico Power (“TNP”) in 2001 with up to 25 MW of firm capacity and associated energy pursuant to an agreement that expires on December 31, 2002. The contract allows TNP to specify a maximum annual amount up to 75 MW with one year’s notice. The Company received notice from TNP in December 2000 that TNP was electing to take 75 MW in 2002. The Company also sold 40 MW of firm capacity and associated energy to CFE during May 2001 and 100 MW during June through September 2001.
C. Palo Verde and Other Jointly-Owned Utility Plant
The Company owns a 15.8% interest in each of the three nuclear generating units and Common Facilities at Palo Verde. The Palo Verde Participants include the Company, five other utilities and Arizona Public Service Company (“APS”), which 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 proportionate 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.
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, 2001 and 2000 is as follows (in thousands):
Decommissioning. Pursuant to the ANPP Participation Agreement and federal law, the Company must fund its share of the estimated costs to decommission Palo Verde Units 1, 2 and 3, including the Common Facilities, over their estimated useful lives of 40 years (to 2024, 2025 and 2027, respectively).
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The Company’s funding requirements are determined periodically based upon engineering cost estimates performed by outside engineers retained by APS.
In December 2001, the Palo Verde Participants received a preliminary version of the 2001 decommissioning study. The 2001 preliminary study determined that the Company will have to fund approximately $312.2 million (stated in 2001 dollars) to cover its share of decommissioning costs. The previous cost estimate from a 1998 study determined that the Company would have to fund approximately $280.5 million (stated in 1998 dollars). The 2001 estimate reflects a 11.3% increase from the 1998 estimate primarily due to increases in estimated costs for site restoration at each unit, spent fuel storage after operations have ceased and for the Unit 2 steam generator storage. The Company anticipates Palo Verde Participant approval of the 2001 preliminary study in the second quarter of 2002 with no significant change. See “Spent Fuel Storage” below.
Although the 2001 preliminary study was based on the latest available information, there can be no assurance that decommissioning cost estimates will not continue to increase in the future or that regulatory requirements will not change. In addition, until a new low-level radioactive waste repository opens and operates for a number of years, estimates of the cost to dispose of low-level radioactive waste are subject to significant uncertainty. The decommissioning study is updated every three years and a new study is expected to be completed in 2004. See “Disposal of Low-Level Radioactive Waste” below.
Historically, regulated utilities such as the Company have been permitted to collect in rates the costs of nuclear decommissioning. Under deregulation legislation in both Texas and New Mexico, the Company expects to continue to be able to collect from customers the costs of decommissioning. The collection mechanism in both states will be a “non-bypassable wires charge” through which all customers, even those who choose to purchase energy from a supplier other than the Company, will pay a fee to the Company’s electric distribution subsidiary. The amount of this fee will be approved by the Texas and New Mexico Commissions and will cover decommissioning, among other things. In the Company’s case, the fee will begin to be collected in Texas following the end of the Freeze Period in August 2005 and in New Mexico in 2007, which is the current date for the beginning of retail deregulation. While the Company is entitled to collect decommissioning costs in full under Texas law, there is some uncertainty in New Mexico as to the ability to collect 100% of such costs. See Note B.
The Company has established external trusts 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, 2001 and 2000, the fair market value of the trust funds was approximately $60.9 million and $60.2 million, respectively, which is reflected in the Company’s balance sheets in deferred charges and other assets.
Spent Fuel Storage. The spent fuel storage facilities at Palo Verde will have sufficient capacity to store all fuel expected to be discharged from normal operation of all three Palo Verde units through 2003. Alternative on-site storage facilities are currently being constructed to supplement existing facilities. Spent fuel will be removed from the original facilities as necessary and placed in special storage casks which will be stored at the new facilities until accepted by the DOE for permanent disposal. The alternative facilities will be built in stages to accommodate casks on an as needed basis and
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are expected to be available for use by the end of 2002. 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. In November 1989, the DOE 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.
In July 1998, APS filed, on behalf of all Palo Verde Participants, a petition for review with the United States Court of Appeals for the District of Columbia Circuit seeking confirmation that findings by the Circuit Court in a prior case brought by Northern States Power regarding the DOE’s failure to comply with its obligation to begin accepting spent nuclear fuel would apply to all spent nuclear fuel contract holders. The Circuit Court held APS’ petition in abeyance pending the United States Supreme Court’s decision to review the Northern States Power case. In November 1998, the Supreme Court denied review of this case. The Circuit Court subsequently dismissed APS’ petition after the Circuit Court issued clarifying orders essentially granting the relief sought by APS. APS is monitoring pending litigation between the DOE and other nuclear operators before initiating further legal proceedings or other procedural measures on behalf of the Palo Verde Participants to enforce the DOE’s statutory and contractual obligations. The Company is unable to predict the outcome of these matters at this time.
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 expensed as incurred until an agreement is reached with the DOE for recovery of these costs. However, the Company cannot predict when, if ever, these additional costs will be recovered from the DOE.
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. However, 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.
Steam Generators. Palo Verde has experienced some degradation in the steam generator tubes of each unit. APS has undertaken an ongoing investigation and analysis and has performed corrective
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actions designed to mitigate further degradation. Corrective actions have included changes in operational procedures designed to lower the operating temperatures of the units, chemical cleaning and the implementation of other technical improvements.
The projected service lives of the units’ steam generators are reassessed by APS periodically in conjunction with inspections made during scheduled outages of the Palo Verde units. In December 1999, the Palo Verde Participants unanimously approved installation of new steam generators in Unit 2. This decision was based on an analysis of the net economic benefit from expected improved performance of the unit and the need to realize continued production from that unit over its full licensed life. APS has advised the Company that the fabrication of Unit 2 steam generators is proceeding on schedule, with plans to install the replacement steam generators at Unit 2 during the fall 2003 refueling outage. The Company’s portion of total costs associated with construction and installation of new steam generators in Unit 2 is currently estimated not to exceed $45 million, including approximately $4.9 million of replacement power costs.
Recently, APS discovered potential accelerated degradation in the tubes in Units 1 and 3 and has tentatively concluded that it may be economically desirable to replace the steam generators at those units. While the economic analysis is not yet complete, and a final determination of whether Units 1 and 3 will require steam generator replacement to operate over their full licensed lives has not yet been made, the Company and the other participants have approved the expenditure of $25.6 million (the Company’s portion being $4.04 million) in 2002 to procure long lead time materials for fabrication of a spare set of steam generators for either Unit 1 or 3. The Company also anticipates a request from APS in the summer of 2002 for approval to spend up to $70.0 million (the Company’s portion being $11.0 million) for the fabrication of one spare set of steam generators to be used in either Unit 1 or 3. These actions will provide the Palo Verde participants an option to replace the steam generators at either Unit 1 or 3 as early as fall 2005, should they ultimately choose to do so. Any such replacements would also require the unanimous approval of the Palo Verde participants.
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 may request recovery of a portion of these costs through regulated rates in New Mexico. See Note B. Finally, the Company cannot assure that it will be able to recover these capital costs through its wholesale power rates or its competitive retail rates that become applicable after the start of competition.
Liability and Insurance Matters. In 1957, Congress enacted the Price-Anderson Act as an amendment to the Atomic Energy Act to provide a system of financial protection for persons who may be injured and persons who may be liable for a nuclear incident. The amount of DOE indemnification currently available under the act is $9.43 billion. Additionally, the Palo Verde Participants have public liability insurance against nuclear energy hazards up to the full limit of liability under the Price-Anderson Act. The insurance consists of $200 million of primary liability insurance provided by commercial insurance carriers, with the balance being provided by an industry-wide retrospective assessment program, pursuant to which industry participants would be required to pay a retrospective assessment to cover any loss in excess of $200 million. Effective August 1998, the maximum retrospective assessment per reactor for each nuclear incident is approximately $88.1 million, subject to
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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 Price-Anderson Act was amended in 1988 to extend its term until August 1, 2002. On that date, the DOE’s authority to provide DOE indemnification in a contract will expire. Accordingly, if the Price-Anderson Act is not extended, the DOE indemnification will not cover activity under any contract entered into after August 1, 2002. That expiration will not affect activity under a contract in effect on that date. In November 2001, the U.S. House of Representatives voted in favor of reauthorization of the Price-Anderson Act. The measure, H.R. 2983, extends Price-Anderson coverage for an additional fifteen years. The U.S. Senate could take up the measure early in the second session of the 107th Congress.
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. Finally, the Company 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.
D. 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.
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 will 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.
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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 2001, 2000 and 1999:
Stock option awards provide for vesting periods of up to six years. Stock options outstanding and exercisable at December 31, 2001 are as follows:
The number of stock options exercisable and the weighted average exercise price of these stock options at December 31, 2001, 2000 and 1999 are as follows:
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The Company has adopted the disclosure-only provisions of SFAS No. 123. Accordingly, compensation expense is only recognized for any intrinsic value of stock option grants at the measurement date. Had compensation expense for the plan been determined based on the fair value at the grant date, consistent with the provisions of SFAS No. 123, the Company’s net earnings and earnings per share would have been reduced to the pro forma amounts presented below:
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 2001, 2000 and 1999 are presented below:
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 four 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 time of grant is recorded as unearned compensation as a separate component of common stock equity and is amortized to expense over the
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restriction period. During 2001, 2000 and 1999, approximately $1.8 million, $1.6 million and $1.2 million, respectively, related to restricted stock awards was charged to expense. The following table summarizes the vested and unvested restricted stock awards for 2001, 2000 and 1999:
The weighted average market values at grant date for restricted stock awarded during 2001, 2000 and 1999 are $13.87, $9.93 and $8.14, 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.
Common Stock Repurchase Program
The Company’s Board of Directors previously approved two stock repurchase programs allowing the Company to purchase up to twelve million of its outstanding shares of common stock. On February 7, 2002, the Company’s Board of Directors approved a third stock repurchase program allowing the Company to purchase up to three million shares of common stock. As of December 31, 2001, the Company had repurchased 11,921,329 shares of common stock under these programs for approximately $133.9 million, including commissions. The Company expects to continue to make purchases primarily in the open market at prevailing prices and will also engage in private transactions, if appropriate. Any repurchased shares will be available for issuance under employee benefit and stock option plans, or may be retired.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Reconciliation of Basic and Diluted Earnings Per Common Share
The reconciliation of basic and diluted earnings per common share before extraordinary item is presented below:
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Options that were excluded from the computation of diluted earnings per common share because the exercise price was greater than the average market price of the common shares for the period are listed below:
1)
60,000 options granted May 29, 1998 at an exercise price of $9.50 were excluded for all of 1999 and the first quarter of 2000.
2)
100,000 options granted January 11, 1999 at an exercise price of $8.75 were excluded for the first and second quarters of 1999.
3)
42,432 options granted January 1, 2000 at an exercise price of $9.81 were excluded for the first quarter of 2000.
4)
50,000 options granted March 15, 2000 at an exercise price of $9.50 were excluded for the first quarter of 2000.
5)
2,107 options granted October 1, 2000 at an exercise price of $13.77 were excluded for the fourth quarter of 2000 and the first quarter of 2001.
6)
150,000 options granted December 15, 2000 at an exercise price of $12.60 were excluded for the first quarter of 2001.
7)
2,941 options granted January 1, 2001 at an exercise price of $13.20 were excluded for the first quarter of 2001.
8)
150,000 options granted May 10, 2001 at an exercise price of $14.95 were excluded for the second, third and fourth quarters of 2001.
9)
795 options granted April 1, 2001 at an exercise price of $14.60 were excluded for the third and fourth quarters of 2001.
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10)
1,424 options granted July 1, 2001 at an exercise price of $15.99 were excluded for the third and fourth quarters of 2001.
11)
100,000 options granted April 23, 2001 at an exercise price of $14.00 were excluded for the fourth quarter of 2001.
E. Preferred Stock and Accumulated Other Comprehensive Income (Loss)
In March 1999, after obtaining required consents of holders of certain of the Company’s outstanding debt securities, the Company redeemed its Series A Preferred Stock. The Company paid the redemption price of approximately $139.6 million, accrued cash dividends of $1.3 million, and premium, fees and costs of securing the consents aggregating $9.6 million. The preferred stock had an annual dividend rate of 11.40%.
Following is a summary of the changes in the preferred stock for 1999:
Accumulated other comprehensive income (loss) consists of the following components (in thousands):
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F. 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 C and 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, on or after February 1, 2006. 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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Repurchases, excluding redemption upon maturity, of First Mortgage Bonds made during 2001, 2000 and 1999 are as follows (in thousands):
Internally generated funds were used for the above repurchases. Extraordinary losses of $2.2 million, $1.3 million, and $3.3 million, net of tax, were recorded in 2001, 2000 and 1999, respectively, which relate to these repurchases and include the premiums paid and the unamortized issuance costs for these repurchased First Mortgage Bonds. See Note G.
(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, the bonds may be required to be repurchased at the holder’s option or are subject to mandatory redemption. The bonds are redeemable at the option of the Company under certain circumstances. In August 2000, the Company remarketed all four series of the bonds and recorded an extraordinary loss of $0.5 million, net of tax, for the related unamortized issuance costs. The interest rates were fixed for five years for the 6.375% bonds and two years for the 6.15% bonds. This remarketing allowed the Company to discontinue the letters of credit and related First Mortgage Collateral Series Bonds (“Collateral Series Bonds”) that previously enhanced the bond issues. The Company anticipates remarketing the bonds at the end of the two and five year periods, as applicable. The 6.15% bonds are classified as current maturities at December 31, 2001 since they are within one year of being remarketed. The 6.375% bonds are due to be remarketed in 2005.
(3)
Promissory Note
The note has an annual interest rate of 5.5% and is secured by certain furniture and fixtures.
(4)
Nuclear Fuel Financing
The Company has available a $100 million credit facility that was renewed for a three-year term in January 2002. 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 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 2001.
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As of December 31, 2001, 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.
G. Income Taxes
The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and liabilities at December 31, 2001 and 2000 are presented below (in thousands):
The deferred tax asset valuation allowance decreased by approximately $17.7 million, $0.7 million, and $0.7 million in 2001, 2000 and 1999, respectively. The 2001 valuation allowance decrease of $17.7 million consists of (i) a $2.8 million writedown related to expired investment tax credits of $4.3 million less deferred tax benefits of $1.5 million; (ii) a $8.7 million writedown related to the expiration of state net operating loss (“NOL”) carryforwards at the end of 2001 and (iii) a $6.2 million
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writedown of state valuation allowance, which netted with associated federal tax benefits of $2.2 million resulted in a credit to capital in excess of stated value of $4.0 million in accordance with Statement of Position 90-7, “Financial Reporting by Entities in Reorganization Under the Bankruptcy Code” (“SOP 90-7”), to recognize a tax benefit for valuation allowance that was not used. The decreases of $0.7 million for both 2000 and 1999 were due to a reduction of unused state NOL carryforward benefits, which had valuation allowances recorded against them.
Based on the average annual book income before taxes for the prior three years, 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 $9.9 million at December 31, 2001, 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 2001, 2000 and 1999 results primarily from the accrual of alternative minimum tax (“AMT”). Deferred federal income tax includes an offsetting AMT benefit of $3.1 million, $2.1 million and $2.1 million for 2001, 2000 and 1999, respectively.
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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):
As of December 31, 2001, the Company had $172 million of federal tax NOL carryforwards, $16.1 million of investment tax credit (“ITC”) carryforwards, and $21.9 million of AMT credit carryforwards. If unused, the NOL carryforwards would expire at the end of 2011, the ITC carryforwards would expire in 2002 through 2005, and the AMT credit carryforwards have an unlimited life. The Company recorded a writedown of its expired state NOL carryforwards at the end of 2001. These tax attributes are subject to change by the Internal Revenue Service (the “IRS”) which recently concluded the field work on its examination of the Company’s 1996 through 1998 federal income tax returns. The Company recorded a $2.6 million adjustment to reduce its estimated contingent tax liabilities based upon discussions and agreed issues with taxing authorities. This $2.6 million adjustment was included as a component of deferred income tax expense. See Note H for further discussion of the IRS examination.
H. Commitments and Contingencies
Power Contracts
As of December 31, 2001, the Company had entered into the following agreements with various counterparties for forward firm purchases and sales of electricity:
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The Company also has an agreement with a counterparty for power exchanges under which the Company will receive 80 MW of on-peak capacity and associated energy during 2002 at the Eddy County tie and concurrently deliver the same amount at Palo Verde and/or Four Corners. The on-peak exchange amount will decrease to 30 MW for 2003 through 2005. The agreement also gives the counterparty the option to deliver up to 133 MW of off-peak capacity and associated energy to the Company at the Eddy County tie from 2002 through 2005 in exchange for the same amount of energy concurrently delivered by the Company at Palo Verde and/or Four Corners. The Company will receive a guaranteed margin on any energy exchanged under the off-peak agreement.
As of December 31, 2001, the Company had an immaterial outstanding net receivable of approximately $0.2 million from Enron related to prepetition claims for which the Company has provided an allowance in its general allowance for bad debts. The Company is party to a power purchase contract with Enron requiring deliveries of electricity to the Company during 2002. If Enron fails to perform under this contract, the Company believes that it will be able to obtain replacement power at prices lower than those payable to Enron under the contract.
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 exercise continuing jurisdiction over facility modifications. Environmental regulations can change rapidly and are difficult to predict. Substantial expenditures may be required to comply with these regulations. The Company analyzes the costs of its obligations arising from environmental matters on an ongoing basis, and management believes it has made adequate provision in its financial statements to meet such obligations. Currently, the Company has provision for environmental remediation obligations of approximately $0.6 million. However, unforeseen expenses associated with compliance could have a material adverse effect on the future operations and financial condition of the Company.
The following are expenditures incurred by the Company in 2001, 2000 and 1999 for complying with federal environmental statutes (in thousands):
The Company is not under any environmental investigation by the Environmental Protection Agency, the Texas Natural Resources Conservation Commission or the New Mexico Environment Department. In addition, the Company has not been named as a Potentially Responsible Party pursuant to the Comprehensive Environmental Response, Compensation and Liability Act of 1980.
Tax Matters
The Company’s federal income tax returns for the years 1996 through 1998 have been examined by the IRS. On October 3, 2001, the Company received the IRS notice of proposed deficiency. The primary audit adjustments proposed by the IRS relate to (i) whether the Company was entitled to deduct
EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
payments made on emergence from Chapter 11 bankruptcy proceedings related to Palo Verde and (ii) the settlement of litigation in 1997 concerning a terminated merger during the Company’s bankruptcy. The Company has protested the audit adjustments through administrative appeals and believes that its treatment of the payments is supported by substantial legal authority. In the event that the IRS prevails, the resulting income tax and interest payments could be material to the Company’s financial position, results of operations and cash flows. The Company believes that the audit adjustments can be resolved through administrative appeals and that adequate provision has been made through December 31, 2001 for any additional tax that may be due.
Lease Agreements
The Company has an operating lease for a turbine and certain other related equipment through July 2005, with an extension option for two additional years. The lease requires semiannual lease payments of approximately $0.4 million.
The Company has one other significant operating lease for administrative offices. The lease has a 10-year term and an option to renew for an additional 10 years. 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.
Neither lease agreement imposes 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.
As of December 31, 2001, the Company’s minimum future rental payments for the next five years are as follows (in thousands):
I. 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 none of these claims will have a material adverse effect on the financial position, results of operations and cash flows of the Company.
EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
J. 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, are 21 years of age 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 Retirement Plan. Contributions from the Company are based on the minimum funding amounts required by the Department of Labor and IRS under provisions of the Retirement Plan, as actuarially calculated. The assets of the Retirement Plan are invested in equity securities, fixed income instruments and cash equivalents and are managed by professional investment managers appointed by the Company.
The Company’s Non-Qualified Retirement Income Plan is a non-funded defined benefit plan which covers certain former employees of the Company. During 1996, as part of the Company’s reorganization, the Company terminated the Non-Qualified Retirement Income Plan with respect to all active employees. The benefit cost for the Non-Qualified Retirement Income Plan is based on substantially the same actuarial methods and economic assumptions as those used for the Retirement Plan.
The Company accounts for the Retirement Plan and the Non-Qualified Retirement Income Plan under SFAS No. 87, “Employers’ Accounting for Pensions,” (“SFAS No. 87”). In accordance with SFAS No. 87, the net periodic benefit cost includes amortization of unrecognized net gains or losses, which exceeded 10% of the benefit obligation at the beginning of the year. Unrecognized gains or losses on investment assets of the plans are not amortized. The amortization reflects the excess divided by the average remaining service period of active employees expected to receive benefits.
EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The amounts recognized in the Company’s balance sheets and the funded status of the plans at December 31, 2001 and 2000 are presented below (in thousands):
(1)
Represents a decrease in the discount rate.
Weighted average actuarial assumptions used in determining the actuarial present value of the benefit obligations are as follows:
EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Net periodic benefit cost is made up of the components listed below as determined using the projected unit credit actuarial cost method (in thousands):
Weighted average actuarial assumptions used in determining the net periodic benefit costs are as follows:
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 reach retirement age while working for the Company. Those benefits are accounted for under SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions,” (“SFAS No. 106”). In accordance with SFAS No. 106, the 2001, 2000 and 1999 net periodic benefit cost includes amortization of unrecognized net gains or losses which exceeded 10% of the benefit obligation at the beginning of the year in which they occurred. The amortization reflects the excess divided by the average remaining service period of active employees expected to receive benefits. Unrecognized gains or losses on investment assets of the plans are not amortized. 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 fixed income instruments and cash equivalents and are managed by professional investment managers appointed by the Company.
EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The amounts recognized in the Company’s balance sheets and the funded status of the plan at December 31, 2001 and 2000 are presented below (in thousands):
(1)
Represents a decrease in the discount rate.
Net periodic benefit cost is made up of the components listed below (in thousands):
EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Weighted average assumptions are as follows:
For measurement purposes, a 12% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2002; the rate was assumed to decrease gradually to 6% for 2006 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 trend rates would increase or decrease the benefit obligation by $14.0 million or $11.2 million, respectively. In addition, such a 1% change would increase or decrease the aggregate service and interest cost components of net periodic benefit cost by $1.6 million or $1.3 million, respectively.
All Employee Cash Bonus Plan
The All Employee Cash Bonus Plan (the “Bonus Plan”), was established to reward employees for their contribution in helping the Company attain its corporate goals. Eligible employees below manager level would receive a cash bonus if the Company attained established levels of safety, customer satisfaction and financial results during 2001. The financial goal had to be met before any bonus amounts would be paid and the improvement in financial results had to be greater than any bonus amounts paid. The Company was able to attain the required minimum levels of improvements in all the performance measures for 2001. As a result of the Company’s success, the Company expensed in 2001, 2000 and 1999 approximately $3.7 million, $4.3 million and $4.3 million, respectively, in cash bonuses. The Company has renewed the Bonus Plan in 2002 with similar goals.
K. Franchises and Significant Customers
City of El Paso Franchise
The Company’s major franchise is with the City of El Paso, Texas. The franchise agreement includes a 2% annual franchise fee (approximately $7.2 million per year currently) and provides an arrangement for the Company’s utilization of public rights-of-way necessary to serve its retail customers within the City of El Paso. The franchise with the City of El Paso extends through August 1, 2005.
Las Cruces Franchise
The Company and Las Cruces entered into a seven-year franchise agreement with a 2% annual franchise fee (approximately $1.0 million per year currently) for the provision of electric distribution service in February 2000. 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
EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
distribution system that serves Las Cruces at a purchase price of 130% of the Company’s book value at that time. If Las Cruces exercises this option, it is prohibited from reselling the distribution assets for two years. If Las Cruces fails to exercise this option, the franchise and standstill agreements will be extended for an additional two years.
Military Installations
The Company currently serves Holloman Air Force Base (“Holloman”), White Sands Missile Range (“White Sands”) and the United States Army Air Defense Center at Fort Bliss (“Ft. Bliss”). The Company’s sales to the military bases represent approximately 3% of annual operating revenues. The Company currently has long-term contracts with all three military bases that it serves. The Company signed a contract with Ft. Bliss in December 1998, under which Ft. Bliss will take service from the Company through December 2008. The Company has a contract to provide retail electric service to Holloman for a ten-year term which began in December 1995. In May 1999, the Army and the Company entered into a new ten-year contract to provide retail electric service to White Sands.
L. Financial Instruments
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.
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 at December 31, 2001 and 2000 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.
EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
As of January 1, 2001, the Company adopted SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS No. 133”), as amended, including implementation guidance discussed by the Financial Accounting Standards Board’s (the “FASB”) Derivatives Implementation Group (the “DIG”) and cleared by the FASB as of January 1, 2001. 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 determined, upon implementation of SFAS No. 133, that all such contracts 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.
At July 1, 2001, the Company implemented DIG Issue C10, “Scope Exceptions: Can Option Contracts and Forward Contracts with Optionality Features Qualify for the Normal Purchases and Normal Sales Exception,” DIG Issue C15, “Scope Exceptions: Normal Purchases and Normal Sales Exception for Option-Type Contracts and Forward Contracts in Electricity,” and DIG Issue C16, “Scope Exceptions: Applying the Normal Purchases and Normal Sales Exception to Contracts That Combine a Forward Contract and a Purchased Option Contract.” Based upon this implementation, 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, 2001, the variable, market-based pricing provisions of existing gas contracts are such that these derivative instruments have no significant fair value. The Company also determined that, as of December 31, 2001, all existing power sales and purchases contracts met the specific criteria listed in DIG Issue C15 and, therefore, continue to qualify for the normal purchases and normal sales exception.
The FASB has continued to issue additional guidance on SFAS No. 133, including providing revised guidance on DIG Issue C15 on December 28, 2001. The ultimate effects of this revised guidance, which will be implemented on April 1, 2002, may impact the Company’s application of SFAS No. 133.
EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
M. Selected Quarterly Financial Data (Unaudited)
Item
9.
Item
9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Not applicable.
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 2002 Annual Meeting of Shareholders (the “2002 Proxy Statement”). 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.
Item 11.
Item 11. Executive Compensation
Incorporated herein by reference from the 2002 Proxy Statement.
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management
Incorporated herein by reference from the 2002 Proxy Statement.
Item 13.
Item 13. Certain Relationships and Related Transactions
Incorporated herein by reference from the 2002 Proxy Statement.
PART IV
Item 14.
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K
(a) Documents filed as a part of this report:
Page
1. Financial Statements:
See Index to Financial Statements
2. Financial Statement Schedules:
All schedules are omitted as the required information is not applicable or is included in the financial statements or related notes thereto.
3. Exhibits
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 EXHIBITS
4.04-01
-
Supplemental Loan Agreement No. 1, dated as of February 12, 1996, related to Exhibit 4.04. (Exhibit 4.04-01 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1995)
4.05
-
Remarketing Agreement, dated as of July 1, 1994, between the Company and Smith Barney Inc., related to the Pollution Control Bonds referred to in Exhibit 4.03. (Exhibit 4.04 to the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 1994)
4.05-01
-
Amendment Agreement, dated August 16, 2000, to Exhibits 4.05, 4.11 and 4.21. (Exhibit 4.05-01 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2000)
4.06
-
Tender Agreement, dated as of July 1, 1994, between the Company and Smith Barney Inc., related to the Pollution Control Bonds referred to in Exhibit 4.03. (Exhibit 4.05 to the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 1994)
4.07
-
Ordinance No. 94-1018 adopted by the City Council of the City of Farmington, New Mexico, on October 18, 1994, authorizing and providing for the issuance by the City of Farmington, New Mexico, of $33,300,000 principal amount of its Adjustable Tender Pollution Control Revenue Refunding Bonds, 1994 Series A (El Paso Electric Company Four Corners Project). (Exhibit 4.07 to the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 1994)
4.07-01
-
Ordinance No. 96-1035 adopted by the City Council of the City of Farmington, New Mexico, on January 23, 1996 as Supplemental Ordinance No. 1, related to Exhibit 4.07. (Exhibit 4.07-01 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1995)
4.08
-
Resolution No. 94-798 adopted by the City Council of the City of Farmington, New Mexico, on October 18, 1994, relating to the issuance of the Pollution Control Bonds referred to in Exhibit 4.07. (Exhibit 4.08 to the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 1994)
4.09
-
Amended and Restated Installment Sale Agreement, dated as of November 1, 1994, between the Company and the City of Farmington, New Mexico, relating to the Pollution Control Bonds referred to in Exhibit 4.07. (Exhibit 4.09 to the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 1994)
4.10
-
Representation and Indemnity Agreement, dated as of October 31, 1994, between the Company, the City of Farmington, New Mexico, and Smith Barney Inc., relating to the Pollution Control Bonds referred to in Exhibit 4.07. (Exhibit 4.10 to the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 1994)
4.11
-
Remarketing Agreement, dated as of November 1, 1994, between the Company and Smith Barney Inc., relating to the Pollution Control Bonds referred to in Exhibit 4.07. (Exhibit 4.11 to the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 1994)
4.12
-
Tender Agreement, dated as of November 1, 1994, between the Company and Smith Barney Inc., relating to the Pollution Control Bonds referred to in Exhibit 4.07. (Exhibit 4.12 to the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 1994)
4.13
-
Reserved.
4.14
-
Loan Agreement, dated as of December 1, 1984, between Maricopa County, Arizona Pollution Control Corporation and the Company, relating to $37,100,000 principal amount of Maricopa County, Arizona Pollution Control Corporation Pollution Control Refunding Revenue Bonds, 1984 Series E (El Paso Electric Company Palo Verde Project). (Exhibit 4.27 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1984)
4.14-01
-
Supplemental Loan Agreement, dated as of June 1, 1986, to Exhibit 4.14. (Exhibit 4.29-01 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1986)
4.14-02
-
Supplemental Loan Agreement No. 3, dated as of February 12, 1996, to Exhibit 4.14. (Exhibit 4.14-02 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1995)
4.15
-
Trust Indenture, dated as of December 1, 1984, by and between Maricopa County, Arizona Pollution Control Corporation and MBank El Paso, National Association, as Trustee, securing the Pollution Control Refunding Revenue Bonds referred to in Exhibit 4.14. (Exhibit 4.27-01 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1984)
4.15-01
-
Supplemental Trust Indenture No. 2, dated as of June 1, 1986, to Exhibit 4.15. (Exhibit 4.29-03 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1986)
4.15-02
-
Supplemental Trust Indenture No. 3, dated as of May 6, 1994, to Exhibit 4.15. (Exhibit 4.01 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 1994)
4.15-03
-
Supplemental Trust Indenture No. 4, dated as of November 30, 1995, to Exhibit 4.15, including form of bond. (Exhibit 4.15-03 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1995)
4.16
-
Indexing Agent’s Agreement among Maricopa County, Arizona Pollution Control Corporation, the Company and Smith Barney, Harris Upham & Co., Incorporated, relating to the Pollution Control Refunding Revenue Bonds referred to in Exhibit 4.14. (Exhibit 4.27-03 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1984)
4.17
-
Remarketing Agent Agreement, dated as of May 6, 1994, between Smith Barney Shearson Inc., and the Company, relating to the Pollution Control Refunding Revenue Bonds referred to in Exhibit 4.14. (Exhibit 4.02 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 1994)
10.04
-
Four Corners Project Operating Agreement, dated May 15, 1969, between Arizona Public Service Company, the Company, Public Service Company of New Mexico, Salt River Project Agricultural Improvement and Power District, Southern California Edison Company and Tucson Gas & Electric Company, and Amendments 1 through 10 thereto. (Exhibit 10.04 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1995)
10.04-01
-
Amendment No. 11, dated May 23, 1997, to Exhibit 10.04. (Exhibit 10.04-01 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 1997)
10.05
-
Arizona Nuclear Power Project Participation Agreement, dated August 23, 1973, between Arizona Public Service Company, Public Service Company of New Mexico, Salt River Project Agricultural Improvement and Power District, Tucson Gas & Electric Company and the Company, describing the respective participation ownerships of the various utilities having undivided interests in the Arizona Nuclear Power Project and in general terms defining the respective ownerships, rights, obligations, major construction and operating arrangements of the Parties, and Amendments No. 1 through 13 thereto. (Exhibit 10.05 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1995)
10.06
-
ANPP Valley Transmission System Participation Agreement, dated August 20, 1981, and Amendments No. 1 and 2 thereto. APS Contract No. 2253-419.00. (Exhibit 10.06 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1995)
10.07
-
Arizona Nuclear Power Project High Voltage Switchyard Participation Agreement, dated August 20, 1981. APS Contract No. 2252-419.00. (Exhibit 20.14 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1981)
10.07-01
-
Amendment No. 1, dated November 20, 1986, to Exhibit 10.07. (Exhibit 10.11-01 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1986)
10.08
-
Firm Palo Verde Nuclear Generating Station Transmission Service Agreement, between Salt River Project Agricultural Improvement and Power District and the Company, dated October 18, 1983. (Exhibit 19.12 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1983)
10.09
-
Trust Agreement, dated as of May 1, 1980, between The Bank of New York, as Beneficiary, and First Security Bank of Utah, N.A., and Robert S. Clark, as Owner Trustees, establishing a trust designated as El Paso Electric Company (1980) Equipment Trust No. 2. (Exhibit 5-p-1 to Registration Statement No. 2-68414 on Form S-7)
10.10
-
Trust Indenture, dated as of May 1, 1980, between The Connecticut Bank and Trust Company, as Indenture Trustee, and First Security Bank of Utah, N.A., and Robert S. Clark, Owner Trustees. (Exhibit 5-p-2 to Registration Statement No. 2-68414 on Form S-7)
10.11
-
Lease Agreement, dated as of May 1, 1980, between First Security Bank of Utah, N.A., and Robert S. Clark, the Owner Trustees, as Lessor, and the Company, as Lessee, providing for the lease of a combustion turbine and related generation equipment. (Exhibit 5-p-3 to Registration Statement No. 2-68414 on Form S-7)
10.12
-
Participation Agreement, dated as of May 1, 1980, among the Company, as Lessee, The Bank of New York, as Beneficiary, First Security Bank of Utah, N.A., and Robert S. Clark, as Owner Trustees, The Connecticut Bank and Trust Company, as Indenture Trustee, Franklin Life Insurance Company, Woodmen of the World Life Insurance Society, Minnesota Mutual Life Insurance Company, MacCabees Mutual Life Insurance Company and Mutual Service Insurance Company, as Lenders, pertaining to Exhibit 10.11. (Exhibit 5-p-4 to Registration Statement No. 2-68414 on Form S-7)
10.13
-
Interconnection Agreement, as amended, dated December 8, 1981, between the Company and Southwestern Public Service Company, and Service Schedules A through F thereto. (Exhibit 10.13 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1995)
10.13-01
-
Letter Agreement, dated December 19, 1996, modifying Service Schedule E, relating to Exhibit 10.13. (Exhibit 10.13-01 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1996)
10.14
-
Amrad to Artesia 345 KV Transmission System and DC Terminal Participation Agreement, dated December 8, 1981, between the Company and Texas-New Mexico Power Company, and the First through Third Supplemental Agreements thereto. (Exhibit 10.14 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1995)
10.15
-
Interconnection Agreement and Amendment No. 1, dated July 19, 1966, between the Company and Public Service Company of New Mexico. (Exhibit 19.01 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1982)
10.16
-
Southwest New Mexico Transmission Project Participation Agreement, dated April 11, 1977, between Public Service Company of New Mexico, Community Public Service Company and the Company, and Amendments 1 through 5 thereto. (Exhibit 10.16 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1995)
10.16-01
-
Amendment No. 6, dated as of June 17, 1999, to Exhibit 10.16. (Exhibit 10.09 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 1999)
10.17
-
Tucson-El Paso Power Exchange and Transmission Agreement, dated April 19, 1982, between Tucson Electric Power Company and the Company. (Exhibit 19.26 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1982)
10.18
-
Southwest Reserve Sharing Group Participation Agreement, dated January 1, 1998, between the Company, Arizona Electric Power Cooperative, Arizona Public Service Company, City of Farmington, Los Alamos County, Nevada Power Company, Plains Electric G&T Cooperative, Inc., Public Service Company of New Mexico, Tucson Electric Power and Western Area Power Administration. (Exhibit 10.18 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1997)
10.19
-
Power Sales Agreement No. 2, dated December 2, 1986, between the Company and Imperial Irrigation District, and Amendment No. 1 thereto. (Exhibit 10.19 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1995)
10.20
-
Arizona Nuclear Power Project Transmission Project Westwing Switchyard Amended Interconnection Agreement, dated August 14, 1986, between The United States of America; Arizona Public Service Company; Department of Water and Power of the City of Los Angeles; Nevada Power Company; Public Service Company of New Mexico; Salt River Project Agricultural Improvement and Power District; Tucson Electric Power Company; and the Company. (Exhibit 10.72 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1986)
10.21
-
Power Sales Agreement, dated April 29, 1987, between the Company and Texas-New Mexico Power Company, and Amendment No. 1 thereto. (Exhibit 10.21 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1995)
10.22
-
Form of Indemnity Agreement, between the Company and its directors and officers. (Exhibit 10.22 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1995)
10.23
-
Interchange Agreement, executed April 14, 1982, between Comision Federal de Electricidad and the Company. (Exhibit 19.2 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 1991)
10.24
-
Credit Agreement, dated as of February 12, 1996, as amended and restated as of February 8, 1999, between the Company, Chase Manhattan Bank, as agent, and Chase Bank of Texas, National Association, as Trustee. (Exhibit 10.24 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1998)
10.24-01
-
Amendment Agreement, dated as of February 8, 1999, to Exhibit 10.24. (Exhibit 10.24-01 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1998)
10.25
-
Restricted Stock Award Agreement, dated as of January 17, 1997, with James S. Haines, Jr. (Exhibit 99.02 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1996)
10.26
-
Stock Option Agreement, dated as of December 15, 2000, with James S. Haines, Jr. (Exhibit 10.26 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2000)
10.27
-
Employment Agreement for James S. Haines, Jr., dated April 30, 1996. (Exhibit 10.30 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 1996)
10.27-01
-
Amendment No. 1, dated as of December 15, 2000, to Exhibit 10.27. (Exhibit 10.27-01 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2000)
10.28
-
Restatement of Decommissioning Trust Agreement, dated as of February 12, 1996, between the Company and Boatmen’s Trust Company of Texas, as Decommissioning Trustee for Palo Verde Unit 1. (Exhibit 10.30 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1995)
10.29
-
Restatement of Decommissioning Trust Agreement, dated as of February 12, 1996, between the Company and Boatmen’s Trust Company of Texas, as Decommissioning Trustee for Palo Verde Unit 2. (Exhibit 10.31 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1995)
10.30
-
Restatement of Decommissioning Trust Agreement, dated as of February 12, 1996, between the Company and Boatmen’s Trust Company of Texas, as Decommissioning Trustee for Palo Verde Unit 3. (Exhibit 10.32 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1995)
10.31
-
Spent Fuel Trust Agreement, dated as of February 12, 1996, between the Company and Boatmen’s Trust Company of Texas, as Spent Fuel Trustee. (Exhibit 10.33 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1995)
10.32
-
Trust Agreement, dated as of February 12, 1996, between the Company and Texas Commerce Bank National Association, as Trustee of the Rio Grande Resources Trust II. (Exhibit 10.34 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1995)
10.33
-
Purchase Contract, dated as of February 12, 1996, between the Company and Texas Commerce Bank National Association, as Trustee of the Rio Grande Resources Trust II. (Exhibit 10.35 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1995)
10.34
-
Employment Agreement for Helen Knopp, dated April 30, 1999. (Exhibit 10.46 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1999)
10.35
-
Employment Agreement for Earnest A. Lehman, dated January 5, 1999. (Exhibit 10.38 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1998)
10.36
-
Form of Change of Control Agreement between the Company and certain key officers of the Company. (Exhibit 10.01 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 1999)
10.37
-
Form of Restricted Stock Award Agreement between the Company and certain key officers of the Company. (Exhibit 99.04 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 1998)
10.38
-
Form of Stock Option Agreement between the Company and certain key officers of the Company. (Exhibit 99.01 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 1998)
10.39
-
Form of Directors’ Restricted Stock Award Agreement between the Company and certain directors of the Company. (Exhibit 10.07 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 1999)
10.40
-
Form of Stock Option Agreement between the Company and certain directors of the Company. (Exhibit 99.17 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1997)
10.41
-
Stock Option Agreement, dated as of April 26, 1999, with James S. Haines, Jr. (Exhibit 10.05 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 1999)
10.42
-
Stock Option Agreement, dated as of January 17, 1997, with James S. Haines, Jr. (Exhibit 99.03 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1996)
10.42-01
-
Amendment No. 1, dated April 30, 1997, to Exhibit 10.42. (Exhibit 99.03-01 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1997)
10.43
-
El Paso Electric Company 1999 Long-Term Incentive Plan. (Exhibit 4.1 to Registration Statement No. 333-82129 on Form S-8)
10.44
-
Settlement Agreement, dated as of February 24, 2000, with the City of Las Cruces. (Exhibit 10.01 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2000)
10.45
-
Franchise Agreement, dated April 3, 2000, between the Company and the City of Las Cruces. (Exhibit 10.02 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2000)
10.46
-
Stock Option Agreements, dated as of January 1, 2001 and April 1, 2001, with Wilson K. Cadman. (Identical in all material respects to Exhibit 99.17 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1997) (Exhibit 10.03 to Company’s Quarterly Report on Form 10-Q for quarter ended March 31, 2001)
10.47
-
Form of Directors’ Restricted Stock Award Agreement, dated as of May 10, 2001, between the Company and George W. Edwards, Jr. (Identical in all material respects to Exhibit 10.07 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 1999) (Exhibit 10.04 to Company’s Quarterly Report on Form 10-Q for quarter ended June 30, 2001)
10.48
-
Form of Change of Control Agreement, dated as of April 23, 2001, between the Company and Hector Puente. (Identical in all material respects to Exhibit 10.01 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 1999) (Exhibit 10.06 to Company’s Quarterly Report on Form 10-Q for quarter ended June 30, 2001)
10.49
-
Employment Agreement for Hector Puente, dated April 23, 2001. (Exhibit 10.07 to Company’s Quarterly Report on Form 10-Q for quarter ended June 30, 2001)
10.50
-
Form of Stock Option Agreement, dated as of April 23, 2001, between the Company and Hector Puente. (Identical in all material respects to Exhibit 99.01 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 1998) (Exhibit 10.08 to Company’s Quarterly Report on Form 10-Q for quarter ended June 30, 2001)
10.51
-
Stock Option Agreement, dated as of July 1, 2001, with Wilson K. Cadman. (Identical in all material respects to Exhibit 99.17 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1997) (Exhibit 10.09 to Company’s Quarterly Report on Form 10-Q for quarter ended September 30, 2001)
10.52
-
Stock Option Agreement, dated as of October 1, 2001, with Mr. Wilson K. Cadman. (Identical in all material respects to Exhibit 99.17 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1997)
10.53
-
Stock Option Agreement, dated as of November 5, 2001, with Gary R. Hedrick. (Identical in all material respects to Exhibit 99.01 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 1998)
10.54
-
Stock Option Agreement, dated as of November 12, 2001, with Terry Bassham. (Identical in all material respects to Exhibit 99.01 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 1998)
10.55
-
Stock Option Agreement, dated as of November 26, 2001, with Julius F. Bates. (Identical in all material respects to Exhibit 99.01 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 1998)
10.56
-
Directors’ Restricted Stock Award Agreement, between the Company and certain directors of the Company. (Identical in all material respects to Exhibit 10.07 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 1999)
10.57
-
Restricted Stock Award Agreement with Mr. James S. Haines, Jr. (Identical in all material respects to Exhibit 99.04 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 1998)
10.58
-
Restricted Stock Award Agreement, dated as of November 8, 2001 between the Company and for Mr. Gary R. Hedrick. (Identical in all material respects to Exhibit 99.04 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 1998)
*
Filed herewith.

Twelve 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; Michael L. Blough; Gary R. Hedrick; Kathryn Hood; John C. Horne; Helen Williams Knopp; Earnest A. Lehman; Kerry B. Lore; Robert C. McNiel; Eduardo A. Rodriguez; and Guillermo Silva, officers of the Company.

In lieu of non-employee director compensation, four agreements, dated as of October 1, 2000, substantially identical in material respects to this Exhibit, have been entered into with Kenneth R. Heitz; Ramiro Guzman; Patricia Z. Holland-Branch; and Charles A. Yamarone, directors of the Company.
In lieu of non-employee director compensation, eight agreements, dated as of January 1, 2001 and April 1, 2001, substantially identical in material respects to this Exhibit, have been entered into with Ramiro Guzman; Kenneth R. Heitz; Patricia Z. Holland-Branch; and Charles A. Yamarone, directors of the Company.
Twelve agreements, dated as of May 10, 2001, 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 Wertheimer; Charles A. Yamarone; James A. Cardwell; and Wilson K. Cadman, directors of the Company.
Three agreements, dated October 1, 2001, substantially identical in all material respects to this Exhibit, were entered into with Kenneth R. Heitz; Patricia Z. Holland-Branch; Charles A. Yamarone, directors of the Company.

One agreement, dated as of October 1, 2000, substantially identical in all material respects to this Exhibit, has been entered into with Wilson K. Cadman, a director of the Company.
(b)
Reports on Form 8-K:
The following reports on Form 8-K were filed during the last quarter of 2001.
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.
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, Raul A. Carrillo, Jr. and Guillermo Silva, 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 26th day of March 2002.
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.
Signature
Title
Date
/s/ GARY R. HEDRICK
( Gary R. Hedrick)
President and Chief Executive Officer (Principal Executive Officer) and Director
March 26, 2002
/s/ TERRY BASSHAM
(Terry Bassham)
Executive Vice President, Chief Financial and Administrative Officer (Principal Financial Officer)
March 26, 2002
/s/ WILSON K. CADMAN
(Wilson K. Cadman)
Director
March 26, 2002
/s/ JAMES A. CARDWELL
( James A. Cardwell)
Director
March 26, 2002
/s/ JAMES W. CICCONI
(James W. Cicconi)
Director
March 26, 2002
/s/ GEORGE W. EDWARDS, JR.
(George W. Edwards, Jr.)
Director
March 26, 2002
/s/ RAMIRO GUZMAN
(Ramiro Guzman)
Director
March 26, 2002
/s/ JAMES HAINES
(James Haines)
Director
March 26, 2002
/s/ JAMES W. HARRIS
( James W. Harris)
Director
March 26, 2002
/s/ KENNETH R. HEITZ
(Kenneth R. Heitz)
Director
March 26, 2002
/s/ PATRICIA Z. HOLLAND-BRANCH
(Patricia Z. Holland-Branch)
Director
March 26, 2002
/s/ MICHAEL K. PARKS
(Michael K. Parks)
Director
March 26, 2002
/s/ ERIC B. SIEGEL
(Eric B. Siegel)
Director
March 26, 2002
/s/ STEPHEN WERTHEIMER
(Stephen Wertheimer)
Director
March 26, 2002
/s/ CHARLES A. YAMARONE
(Charles A. Yamarone)
Director
March 26, 2002