El Paso Electric Company 10-K 2008
Documents found in this filing:
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
For the fiscal year ended December 31, 2007
For the transition period from to
Commission file number 0-296
El Paso Electric Company
(Exact name of registrant as specified in its charter)
Registrants telephone number, including area code: (915) 543-5711
Securities Registered Pursuant to Section 12(b) of the Act:
Securities Registered Pursuant to Section 12(g) of the Act:
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. YES x NO ¨
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. YES ¨ NO x
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. YES x NO ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrants knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company (as defined in Rule 12b-2 of the Act).
Large accelerated filer x Accelerated filer ¨ Non-accelerated filer ¨ Smaller reporting company ¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). YES ¨ NO x
As of June 30, 2007, the aggregate market value of the voting stock held by non-affiliates of the registrant was $1,109,228,847 (based on the closing price as quoted on the New York Stock Exchange on that date).
As of January 31, 2008, there were 45,150,655 shares of the Companys no par value common stock outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the registrants definitive Proxy Statement for the 2008 annual meeting of its shareholders are incorporated by reference into Part III of this report.
The following abbreviations, acronyms or defined terms used in this report are defined below:
TABLE OF CONTENTS
Certain matters discussed in this Annual Report on Form 10-K other than statements of historical information are forward-looking statements. The Private Securities Litigation Reform Act of 1995 has established that these statements qualify for safe harbors from liability. Forward-looking statements may include words like we believe, anticipate, target, expect, pro forma, estimate, intend and words of similar meaning. Forward-looking statements describe our future plans, objectives, expectations or goals. Such statements address future events and conditions concerning and include, but are not limited to such things as:
These forward-looking statements involve known and unknown risks that may cause our actual results in future periods to differ materially from those expressed in any forward-looking statement. Factors that would cause or contribute to such differences include, but are not limited to, such things as:
These lists are not all-inclusive because it is not possible to predict all factors. A discussion of some of these factors is included in this document under the headings Risk Factors and Managements Discussion and Analysis Summary of Critical Accounting Policies and Estimates and Liquidity and Capital Resources. This report should be read in its entirety. No one section of this report deals with all aspects of the subject matter. Any forward-looking statement speaks only as of the date such statement was made, and we are not obligated to update any forward-looking statement to reflect events or circumstances after the date on which such statement was made except as required by applicable laws or regulations.
El Paso Electric Company is a public utility engaged in the generation, transmission and distribution of electricity in an area of approximately 10,000 square miles in west Texas and southern New Mexico. The Company also serves a wholesale customer in Texas and from time to time a customer in the Republic of Mexico. The Company owns or has significant ownership interests in six electrical generating facilities providing it with a net dependable generating capability of approximately 1,503 MW. For the year ended December 31, 2007, the Companys energy sources consisted of approximately 43% nuclear fuel, 28% natural gas, 7% coal, 22% purchased power and less than 1% generated by wind turbines.
The Company serves approximately 360,000 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 55% and 9%, respectively, of the Companys operating revenues for the year ended December 31, 2007). In addition, the Companys wholesale sales include sales for resale to other electric utilities and power marketers. Principal industrial and other large customers of the Company include United States military installations, including Fort Bliss in Texas and White Sands Missile Range and Holloman Air Force Base in New Mexico, two large universities, and oil, copper refining and steel production facilities.
The Companys 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 January 31, 2008, the Company had approximately 1,000 employees, 44% of whom are covered by a collective bargaining agreement.
The Company makes available free of charge through its website, www.epelectric.com, its annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and all amendments to those reports as soon as reasonably practicable after such material is electronically filed with or furnished to the Securities and Exchange Commission (SEC). In addition, copies of the annual report will be made available free of charge upon written request. The SEC also maintains an internet site that contains reports, proxy and information statements and other information for issuers that file electronically with the SEC. The address of that site is www.sec.gov. The information on the internet site is not incorporated into this document by reference.
The Companys net dependable generating capability of 1,503 MW consists of the following:
Palo Verde Station
The Company owns a 15.8% interest in each of the three nuclear generating units and Common Facilities at Palo Verde, in Wintersburg, Arizona. The Palo Verde Participants include the Company and six other utilities: APS, Southern California Edison Company (SCE), PNM, Southern California Public Power Authority, Salt River Project Agricultural Improvement and Power District (SRP) and the Los Angeles Department of Water and Power. APS serves as operating agent for Palo Verde, and under the ANPP Participation Agreement, the Company has limited ability to influence operations and costs at Palo Verde.
The NRC has granted facility operating licenses and full power operating licenses for Palo Verde Units 1, 2 and 3, which expire in 2024, 2025 and 2027, respectively. In addition, the Company is separately licensed by the NRC to own its proportionate share of Palo Verde.
Pursuant to the ANPP Participation Agreement, the Palo Verde Participants share costs and generating entitlements in the same proportion as their percentage interests in the generating units, and each participant is required to fund its share of fuel, other operations, maintenance and capital costs. The ANPP Participation Agreement provides that if a participant fails to meet its payment obligations, each non-defaulting participant shall pay its proportionate share of the payments owed by the defaulting participant.
NRC. The NRC regulates the operation of all commercial nuclear power reactors in the United States, including Palo Verde. The NRC periodically conducts inspections of nuclear facilities and monitors performance indicators to enable the agency to arrive at objective conclusions about a licensees safety performance. Based on this assessment information and using a cornerstone evaluation system, the NRC determines the appropriate level of agency response and oversight, including supplemental inspections and pertinent regulatory actions as necessary.
In October 2006, the NRC conducted an inspection of the Palo Verde emergency diesel generators after a Palo Verde Unit 3 emergency diesel generator did not activate during routine inspections in July and September 2006. On February 22, 2007, the NRC issued a white finding (low to moderate safety significance) for this matter. Based upon this finding, coupled with a previous NRC yellow finding (substantial safety significance) relating to a 2004 matter involving Palo Verdes safety
injection systems, the NRC placed Palo Verde Unit 3 in the multiple/repetitive degraded cornerstone column of the NRCs action matrix which has resulted in an enhanced NRC inspection regimen. This enhanced inspection regimen and resulting corrective actions has resulted in increased operating costs at the plant. Of the 104 commercial nuclear reactors in the United States regulated by the NRC, only Palo Verde Unit 3 was listed in the multiple/repetitive degraded cornerstone category as of the end of 2007. The Company is currently unable to predict the impact that the NRCs increased oversight may have on Palo Verdes operations and the cost of operations.
Decommissioning. Pursuant to the ANPP Participation Agreement and federal law, the Company must fund its share of the estimated costs to decommission Palo Verde Units 1, 2 and 3, including the Common Facilities, through the term of their respective operating licenses. The Company is required to maintain a minimum accumulation and a minimum funding level in its decommissioning account at the end of each annual reporting period during the life of the plant. The Company has established external trusts with an independent trustee which enable the Company to record a current deduction for federal income tax purposes of a portion of amounts funded. At December 31, 2007, the Companys decommissioning trust fund had a balance of $130.7 million and the Company was above its minimum funding level. The Company will continue to monitor the status of its decommissioning funds and adjust its deposits, if necessary, to remain at or above its minimum accumulation requirements in the future.
Decommissioning costs are estimated every three years based upon engineering cost studies performed by outside engineers retained by APS. In 2005, the Palo Verde Participants approved the 2004 Palo Verde decommissioning study (2004 Study). The 2004 Study estimated that the Company must fund approximately $335.7 million (stated in 2004 dollars) to cover its share of decommissioning costs. Although the 2004 Study was based on the latest available information, there can be no assurance that decommissioning cost estimates will not 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. A study of decommissioning costs was performed in 2007 (2007 Study). Preliminary results of the 2007 Study indicate a reduction in decommissioning costs from the 2004 Study which, if adopted, will result in lower asset retirement obligations and lower expenses in the future. The 2007 Study is expected to be approved in the second quarter of 2008. See Spent Fuel Storage and Disposal of Low-Level Radioactive Waste below.
Spent Fuel Storage. The original spent fuel storage facilities at Palo Verde had sufficient capacity to store all fuel discharged from normal operation of all three Palo Verde units through 2003. Alternative on-site storage facilities and casks have been constructed to supplement the original facilities. In March 2003, APS began removing spent fuel from the original facilities as necessary, and placing it in special storage casks which will be stored at the new facilities until accepted by the DOE for permanent disposal. The 2004 Study assumed that costs to store fuel on-site will become the responsibility of the DOE after 2037. APS believes that spent fuel storage or disposal methods will be available to allow each Palo Verde unit to continue to operate through the term of its operating license.
Pursuant to the Nuclear Waste Policy Act of 1982, as amended in 1987 (the Waste Act), the DOE is legally obligated to accept and dispose of all spent nuclear fuel and other high-level radioactive waste generated by all domestic power reactors. In accordance with the Waste Act, the DOE entered into a spent nuclear fuel contract with the Company and all other Palo Verde Participants. The DOE has previously reported that its spent nuclear fuel disposal facilities would not be in operation in the near future. 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 DOEs permanent disposal site will commence.
The Company expects to incur significant costs for on-site spent fuel storage during the life of Palo Verde that the Company believes are the responsibility of the DOE. These costs are assigned to fuel requiring the additional on-site storage and amortized as that fuel is burned until an agreement is reached with the DOE for recovery of these costs. In December 2003, APS, in conjunction with other nuclear plant operators, filed suit against the DOE on behalf of the Palo Verde Participants to recover monetary damages associated with the delay in the DOEs acceptance of spent fuel. On February 28, 2007, APS served on the U.S. Department of Justice its Initial Disclosure of Claimed Damages of $93.4 million (the Companys portion being $14.8 million). This amount includes expenses associated with design, construction, loading, and operation of the Palo Verde independent spent fuel storage installation through December 2006. This amount represents costs incurred to ensure sufficient storage capacity for Palo Verde spent fuel that would not have been incurred had the DOE complied with its standard contract obligation to begin accepting spent fuel from the commercial nuclear power industry beginning in 1998. The Company is unable to predict the outcome of this matter at this time.
Disposal of Low-Level Radioactive Waste. Congress has established requirements for the disposal by each state of low-level radioactive waste generated within its borders. Arizona, California, North Dakota and South Dakota have entered into a compact (the Southwestern Compact) for the disposal of low-level radioactive waste. California will act as the first host state of the Southwestern Compact, and Arizona will serve as the second host state. The construction and opening of the California low-level radioactive waste disposal site in Ward Valley has been delayed due to extensive public hearings, disputes over environmental issues and review of technical issues related to the proposed site. Palo Verde is projected to undergo decommissioning during the period in which Arizona will act as host for the Southwestern Compact. The opposition, delays, uncertainty and costs experienced in California demonstrate possible roadblocks that may be encountered when Arizona seeks to open its own waste repository. APS currently believes that interim low-level waste storage methods are or will be available to allow each Palo Verde unit to continue to operate and to store safely low-level waste until a permanent disposal facility is available.
Reactor Vessel Heads. In accordance with applicable NRC requirements, APS conducts regular inspections of reactor vessel heads at Palo Verde Units 1, 2 and 3. In an effort to reduce long-term operating costs at the station related to inspection of the reactor heads, related equipment, and possible repair costs, APS plans to replace reactor vessel heads at Palo Verde. Reactor vessel head replacement is scheduled to occur at Units 1, 2 and 3 in 2010, 2009 and 2009, respectively. The Companys share of the costs for this project is estimated to be $21.3 million.
Liability and Insurance Matters. The Palo Verde participants have insurance for public liability resulting from nuclear energy hazards to the full limit of liability under federal law currently at $10.8 billion. This potential liability is covered by primary liability insurance provided by commercial insurance carriers in the amount of $300 million and the balance by an industry-wide retrospective assessment program. If a loss at a nuclear power plant covered by the programs exceeds the accumulated funds in the primary level of protection, the Company could be assessed retrospective premium adjustments on a per incident basis. Under federal law, the maximum assessment per reactor under the program for each nuclear incident is approximately $100.6 million, subject to an annual limit of $15 million. Based upon the Companys 15.8% interest in the three Palo Verde units, the Companys maximum potential assessment per incident for all three units is approximately $47.7 million, with an annual payment limitation of approximately $7.1 million.
The Palo Verde Participants maintain all risk (including nuclear hazards) insurance for property damage to, and decontamination of, property at Palo Verde in the aggregate amount of $2.75 billion, a substantial portion of which must first be applied to stabilization and decontamination. The Company has also secured insurance against portions of any increased cost of generation or purchased power and business interruption resulting from a sudden and unforeseen outage of any of the three units. The insurance coverage discussed in this and the previous paragraph is subject to certain policy conditions and exclusions. A mutual insurance company whose members are utilities with nuclear facilities issues these policies. If losses at any nuclear facility covered by this mutual insurance company were to exceed the accumulated funds for these insurance programs, the Company could be assessed retrospective premium adjustments of up to $11.5 million for the current policy period.
Newman Power Station
The Companys Newman Power Station, located in El Paso, Texas, consists of three steam-electric generating units and one combined cycle generating unit with an aggregate net capability of approximately 474 MW. The units operate primarily on natural gas but can also operate on fuel oil.
Rio Grande Power Station
The Companys 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 net capability of approximately 229 MW. The units operate primarily on natural gas but can also operate on fuel oil.
Four Corners Station
The Company owns a 7% interest, or approximately 104 MW, in Units 4 and 5 at Four Corners, located in northwestern New Mexico. Each of the two coal-fired generating units has a total net capability of 739 MW. The Company shares power entitlements and certain allocated costs of the two units with APS (the Four Corners operating agent) and the other participants, PNM, TEP, SCE and SRP.
Four Corners is located on land under easements from the federal government and a lease from the Navajo Nation that expires in 2016, with a one-time option to extend the term for an additional 25 years. Certain of the facilities associated with Four Corners, including transmission lines and almost all of the contracted coal sources, are also located on Navajo land. Units 4 and 5 are located adjacent to a surface-mined supply of coal.
Copper Power Station
The Companys Copper Power Station, located in El Paso, Texas, consists of a 62 MW combustion turbine used primarily to meet peak demands. The unit operates primarily on natural gas but can also operate on fuel oil.
Hueco Mountain Wind Ranch
The Companys 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 of which a portion, currently 28%, can be used as net capability for resource planning purposes.
Transmission and Distribution Lines and Agreements
The Company owns or has significant ownership interests in four major 345 kV transmission lines in New Mexico, three 500 kV lines in Arizona, and owns the transmission and distribution network within its New Mexico and Texas retail service area and operates these facilities under franchise agreements with various municipalities. The Company is also a party to various transmission and power exchange agreements that, together with its owned transmission lines, enable the Company to deliver its energy entitlements from its remote generation sources at Palo Verde and Four Corners to its service area. Pursuant to standards established by the North American Electric Reliability Corporation (formerly the North American Electric Reliability Council) and the Western Electricity Coordinating Council, the Company operates its transmission system in a way that allows it to maintain system integrity in the event that any one of these transmission lines is out of service.
Springerville-Luna-Diablo Line. The Company owns a 310-mile, 345 kV transmission line from TEPs Springerville Generating Plant near Springerville, Arizona, to the Luna Substation near Deming, New Mexico, and to the Diablo Substation near Sunland Park, New Mexico. This transmission line provides an interconnection with TEP for delivery of the Companys generation entitlements from Palo Verde and, if necessary, Four Corners.
West Mesa-Arroyo Line. The Company owns a 202-mile, 345 kV transmission line from PNMs West Mesa Substation located near Albuquerque, New Mexico, to the Arroyo Substation located near Las Cruces, New Mexico. This is the primary delivery point for the Companys generation entitlement from Four Corners, which is transmitted to the West Mesa Substation over approximately 150 miles of transmission lines owned by PNM.
Greenlee-Hidalgo-Luna-Newman Line. The Company owns 40% of a 60-mile, 345 kV transmission line between TEPs Greenlee Substation near Duncan, Arizona to the Hidalgo Substation near Lordsburg, New Mexico, approximately 57% of a 50-mile, 345 kV transmission line between the Hidalgo Substation and the Luna Substation and 100% of an 86-mile, 345 kV transmission line between the Luna Substation and the Newman Power Station. These lines provide an interconnection with TEP for delivery of the Companys entitlements from Palo Verde and, if necessary, Four Corners. The Company owns the Afton 345 kV Substation located approximately 57 miles from the Luna Substation on the Luna-to-Newman portion of the line. The Afton Substation interconnects a generator owned and operated by PNM.
Eddy County-AMRAD Line. The Company owns 66.7% of a 125-mile, 345 kV transmission line from the Companys and PNMs (formerly TNPs) high voltage direct current terminal at the Eddy County Substation near Artesia, New Mexico to the AMRAD Substation near Oro Grande, New Mexico. The Company owns 66.7% of the terminal. This terminal enables the Company to connect its transmission system to that of SPS (a subsidiary of Xcel Energy), providing the Company with access to purchased and emergency power from SPS and power markets to the east.
Palo Verde Transmission and Switchyard. The Company owns 18.7% of two 45-mile, 500 kV lines from Palo Verde to the Westwing Substation located northwest of Phoenix near Peoria, Arizona and 18.7% of a 75-mile, 500 kV line from Palo Verde to the Jojoba Substation, then to the Kyrene Substation located near Tempe, Arizona. These lines provide the Company with a transmission path for delivery of power from Palo Verde. The Company also owns 18.7% of two 500 kV switchyards connected to the Palo Verde-Kyrene 500 kV line: the Hassayampa switchyard adjacent to the southern edge of the Palo Verde 500 kV switchyard and the Jojoba switchyard approximately 24 miles from
Palo Verde. These switchyards were built to accommodate the addition of new generation and transmission in the Palo Verde area.
The Company is subject to regulation with respect to air, soil and water quality, solid waste disposal and other environmental matters by federal, state, tribal and local authorities. Those authorities govern current facility operations and have continuing jurisdiction over facility modifications. Failure to comply with these environmental regulatory requirements can result in actions by regulatory agencies or other authorities that might seek to impose on the Company administrative, civil, and/or criminal penalties. In addition, unauthorized releases of pollutants or contaminants into the environment can result in costly cleanup obligations that are subject to enforcement by regulatory agencies.
These laws and regulations are subject to change and, as a result of those changes, the Company may face additional capital and operating costs to comply. For example, recent developments suggest a growing likelihood of future regulation relating to climate change and greenhouse gas emissions. At the federal level, Congress continues to hold many hearings relating to climate change issues and many bills have been introduced to impose regulation through regulatory schemes including a cap and trade program. The United States Supreme Court has found carbon dioxide, one of the principal greenhouse gases, to be a pollutant under the Clean Air Act, increasing the possibility that the U.S. Environmental Protection Agency will begin to regulate these emissions even in the absence of further action by Congress. In addition, the State of New Mexico, where the Company operates one facility and has an interest in another facility, has joined with California and several other states in the Western Regional Climate Action Initiative and is pursuing initiatives to reduce greenhouse gas emissions in the state. The Company is monitoring these developments and how regulation may affect it. If the United States or individual states in which the Company operates were to regulate greenhouse gas emissions, the Companys fossil fuel generation assets are likely to face additional costs for monitoring, reporting, controlling, or offsetting these emissions.
Another way in which environmental matters may impact the Companys operations and business is the implementation of the U.S. Environmental Protection Agencys Clean Air Interstate Rule which, as applied to the Company, may result in a requirement that it substantially reduce emissions of nitrogen oxides from its power plants in Texas and/or purchase allowances representing other parties emissions reductions starting in 2009. These requirements become more stringent in 2015, and are anticipated to require even further emissions reductions or additional allowance purchases.
The Company takes these regulatory matters seriously and is monitoring these issues so that the Company is best able to effectively adapt to any such changes. Because the Companys generating portfolio has a carbon footprint that compares favorably with other power generating companies, the Company believes such regulations would not impose greater relative burdens on the Company than on most other electric utilities. Environmental regulations like these can change rapidly and those changes are often difficult to predict. While the Company strives to prepare for and implement actions necessary to comply with changing environmental regulations, substantial expenditures may be required for the Company to comply with such regulations in the future and, in some instances, those expenditures may be material. The Company believes it is impossible at present to meaningfully quantify the costs of these potential impacts.
The Company analyzes the costs of its obligations arising from environmental matters on an ongoing basis and believes it has made adequate provision in its financial statements to meet such obligations. As a result of this analysis, the Company has a provision for environmental remediation obligations of approximately $1.4 million as of December 31, 2007, which amounts are related to compliance with federal and state environmental standards. However, unforeseen expenses associated with environmental compliance or remediation may occur and could have a material adverse effect on the future operations and financial condition of the Company.
Along with many other companies, the Company received from the Texas Commission on Environmental Quality (TCEQ) a request for information in 2003 in connection with environmental conditions at a facility in San Angelo, Texas that was operated by the San Angelo Electric Service Company (SESCO). In November 2005, TCEQ proposed the SESCO site for listing on the registry of Texas state superfund sites and mailed notice to more than five hundred entities, including the Company, indicating that TCEQ considers each of them to be potentially responsible parties at the SESCO site. The Company received from the SESCO working group of potentially responsible parties a settlement offer in May 2006 for remediation and other expenses expected to be incurred in connection with the SESCO site. The Companys position is that any liability it may have related to the SESCO site was discharged in the Companys bankruptcy. At this time, the Company has not agreed to a settlement or to otherwise participate in the cleanup of the SESCO site and is unable to predict the outcome of this matter. While the Company has no reason at present to believe that it will incur material liabilities in connection with the SESCO site, it has accrued $0.3 million for potential costs related to this matter.
On September 26, 2006, the Secretary of the New Mexico Environment Department issued a Compliance Order concerning the Companys Rio Grande Generating Station, located in Dona Ana County, New Mexico. The Compliance Order alleges that, on approximately 650 occasions between May 2000 and September 2005, the Rio Grande Generating Station emitted sulfur dioxide, nitrogen oxides or carbon monoxide in excess of its permitted emission rates and failed to properly report these allegedly excess emissions. The Compliance Order asserts a statutory authority to seek a civil penalty of up to $15,000 per violation for each of the violations alleged. The Company disputes the allegations made and has requested a hearing before the New Mexico Environment Department on the matter. While the Company cannot predict the outcome of this matter, it believes these emissions did not violate applicable legal standards and that penalties, if any, should not involve a material liability.
On April 4, 2007, the Company submitted its application for a New Source Review Air Quality Permit/Prevention of Significant Deterioration (PSD) permit to the TCEQ for the new natural-gas electric generating units to be located at its existing Newman plant site in the City of El Paso (Newman Unit 5). The Company expects to receive approval of its PSD application in the second quarter of 2008. Additional environmental permits other than the PSD are not required to begin construction of these new generating units because Newman Unit 5 will be constructed at an existing plant site and other permits are currently in place which will encompass Newman Unit 5.
In May 2007, the Environmental Protection Agency finalized a new federal implementation plan which addresses emissions at the Four Corners Station in northwestern New Mexico of which the Company owns a 7% interest in Units 4 and 5. Arizona Public Service, the Four Corners operating agent, has filed suit against the Environmental Protection Agency relating to this new federal implementation plan in order to resolve issues involving operating flexibility for emission opacity standards. The Company cannot predict the outcome of the suit filed against the Environmental
Protection Agency or whether compliance with the new requirements could have an adverse effect on its capital and operating costs.
Except as described herein, the Company is not aware of any other active investigation of its compliance with environmental requirements by the Environmental Protection Agency, the TCEQ or the New Mexico Environment Department which is expected to result in any material liability. Furthermore, except as described herein, the Company is not aware of any unresolved, potentially material liability it would face pursuant to the Comprehensive Environmental Response, Comprehensive Liability Act of 1980, also known as the Superfund law.
Utility construction expenditures reflected in the following table consist primarily of local generation, expanding and updating the transmission and distribution systems, including growth associated with the expansion of Ft. Bliss, and the cost of capital improvements and replacements at Palo Verde. Studies indicate that the Company will need additional power generation resources to meet increasing load requirements on its system, the costs of which are included in the table below.
The Companys estimated cash construction costs for 2008 through 2011 are approximately $842 million. Actual costs may vary from the construction program estimates shown. Such estimates are reviewed and updated periodically to reflect changed conditions.
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 recoverable from customers in Texas and New Mexico pursuant to applicable regulations. Historical fuel costs and revenues are reconciled periodically in proceedings before the Texas Commission and the NMPRC. See Regulation Texas Regulatory Matters and New Mexico Regulatory Matters.
The nuclear fuel cycle for Palo Verde consists of the following stages: the mining and milling of uranium ore to produce uranium concentrates; the conversion of the uranium concentrates to uranium hexafluoride (conversion services); the enrichment of uranium hexafluoride (enrichment services); the fabrication of fuel assemblies (fabrication services); the utilization of the fuel assemblies in the reactors; and the storage and disposal of the spent fuel. The Palo Verde Participants have contracts in place that will furnish 100% of Palo Verdes operational requirements for uranium concentrates, conversion services and enrichment services through 2008. Such contracts could also provide 100% of enrichment services in 2009 and 2010. The Palo Verde Participants have a contract that will provide 100% of fabrication services until at least 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 nuclear fuel material market has recently been affected by supply disruptions and significant price increases with the cost of uranium having increased significantly in the last few years. The Palo Verde Participants have taken steps to mitigate the effects of future supply disruptions and price increases by changing from a procurement strategy under which nuclear fuel arrives at Palo Verde one month prior to being loaded into a reactor to a strategy where (i) nuclear fuel arrives on site three months before being loaded and (ii) a strategic inventory of converted nuclear fuel material sufficient to provide feed stock for one full reactor reload is stored for future use. This change in procurement strategy increased our cash funding requirements in 2007. In July 2007, the Company expanded its revolving credit facility from $150 million to $200 million which provides for both working capital and up to $120 million for the financing of nuclear fuel. This facility has a five-year term ending April 11, 2011. At December 31, 2007, approximately $83.0 million had been drawn to finance nuclear fuel. This financing is accomplished through a trust that borrows under the credit facility to acquire and process the nuclear fuel. The Company is obligated to repay the trusts borrowings with interest. In the Companys
financial statements, the assets and liabilities of the trust are consolidated and reported as assets and liabilities of the Company.
The Company manages its natural gas requirements through a combination of a long-term supply contract and spot market purchases. The long-term supply contract provides for firm deliveries of gas at market-based index prices. In 2007, the Companys natural gas requirements at the Newman and Rio Grande Power Stations were met with both short-term and long-term natural gas purchases from various suppliers and this practice is expected to continue in 2008. Interstate gas is delivered under a base firm transportation contract. The Company anticipates it will continue to purchase natural gas at spot market prices on a monthly basis for a portion of the fuel needs for the Newman and Rio Grande Power Station. 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 Newman and Rio Grande Power Stations.
Natural gas for the Newman and Copper Power Stations is also supplied pursuant to an intrastate natural gas contract that expired in 2007, but was extended on a short-term basis until a new contract can be negotiated. The Company is currently in the process of renegotiating this contract.
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 Four Corners coal contract expires in 2016 which coincides with the term of the Four Corners Plant lease with the Navajo Nation. Based upon information from APS, the Company believes that Four Corners has sufficient reserves of coal to meet the plants operational requirements for its useful life.
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 Companys resource needs and the economics of the transactions. In 2004, the Company entered into a 20-year contract, beginning in 2006, for the purchase of up to 133 MW of capacity and associated energy from SPS. This contract includes a demand charge, fuel charge, variable operations and maintenance charge, and a transmission charge. The contract provides that, in the event the transactions thereunder are subject to adverse regulatory action, the affected party may initiate discussions with the other party to assess whether modifications to the agreement may be appropriate. If the parties are unable to reach a mutually satisfactory resolution within six months, either party may terminate the contract by providing not less than two years prior written notice to the other party.
The Company previously received notice from SPS that SPS had been subject to adverse regulatory action by the Texas Commission regarding transactions under the contract and that SPS wished to exercise its right to terminate the contract early. As a result, on January 29, 2008, the Company and SPS entered into an amendment to the contract and agreed that the contract will terminate on September 30, 2009.
In June 2006, the Company began exchanging up to 100 MW of capacity and associated energy with Phelps Dodge Energy. The contract provides for Phelps Dodge to deliver energy to the Company from its ownership interest in the Luna Energy Facility, an approximate 570 MW natural gas fired combined cycle generation facility located in Luna County, New Mexico and for the Company to deliver a like amount of energy at the Greenlee delivery point. The Company may purchase up to 100 MW at a specified price at times when energy is not exchanged. The agreement was approved by the FERC and continues through December 31, 2021.
Other purchases of shorter duration were made during 2007 primarily to replace the Companys generation resources during planned and unplanned outages and for economic reasons.
The rates and services of the Company are regulated by incorporated municipalities in Texas, the Texas Commission, the NMPRC, and the FERC. The Texas Commission and the NMPRC have jurisdiction to review municipal orders, ordinances, and utility agreements regarding rates and services within their respective states and over certain other activities of the Company. The FERC has jurisdiction over the Companys wholesale transactions. The decisions of the Texas Commission, NMPRC and the FERC are subject to judicial review.
Texas Regulatory Matters
Texas Rate Agreements. The Company has entered into agreements (Texas Rate Agreements) with El Paso, Commission Staff and other parties in Texas that provide for most retail base rates to remain at their current level through June 30, 2010. During the rate freeze period, if the Companys return on equity falls below the bottom of a defined range, the Company has the right to initiate a rate case and seek an adjustment to base rates. If the Companys return on equity exceeds the top of the range, the Company will refund an amount equal to 50% of the pretax return in excess of the ceiling. The range is based upon a risk premium above a twelve month average of comparable credit quality bond yields and at a twelve month average of such bond yields the range would be approximately 8.3% to 12.3%. During 2007 the Companys return on equity fell within this range.
Pursuant to a rate agreement with El Paso in July 2005, the Company agreed to share with its Texas customers 25% of off-system sales margins and wheeling revenues among other provisions. Under the prior rate agreement, the Company shared 50% of off-system sales margins and wheeling revenues with Texas customers. A request for approval of the off-system sales and wheeling revenue sharing provision was filed with the Texas Commission in January 2006 (PUC Docket No. 32289).
In PUC Docket No. 32289, the Company entered into settlement agreements with the Texas Commission Staff, a large industrial customer, El Paso, Texas Ratepayers Organization to Save Energy, and the Office of the Attorney General of the State of Texas (the State) which (i) extended the rate freeze to all customers in Texas; (ii) extended the earnings sharing provisions to all customers in Texas; (iii) expanded the Companys support of low-income energy efficiency programs; and (iv) provided that after the expiration of the Texas Rate Agreements, the Company will treat wheeling revenues and expenses associated with non-native load in a manner consistent with then-existing Texas Commission rules and other substantive and procedural law. In addition, the agreement with the State provides for the Company to share 90% of off-system sales margins with customers after June 30, 2010 through June 30, 2015. This provision is not binding on the Texas Commission or other settling parties. In addition, the Company agreed that upon the expiration of the rate freeze, it would file a full base rate case with the Texas Commission and the applicable cities having original jurisdiction if requested to do so by the Texas Commission staff, El Paso, the State or the Texas Office of Public Utility Counsel. The Company also retained the right to voluntarily file a full base rate case. The Company currently anticipates that it will need base rate relief in that time frame. On December 8, 2006, the Texas Commission approved the margin sharing provisions of the Texas Rate Agreements in PUC Docket No. 32289 pursuant to the settlement agreements.
Fuel and Purchased Power Costs. Although the Companys base rates are frozen under the Texas Rate Agreements, pursuant to Texas Commission rules and the Texas Rate Agreements, the Companys fuel costs including purchased power energy costs are recoverable from its customers. In January and July of each year, the Company can request adjustments to its fixed fuel factor to more accurately reflect projected energy costs associated with providing electricity, seek recovery of past undercollections of fuel revenues, and refund past overcollections of fuel revenues. All such fuel revenue and expense activities are subject to periodic final review by the Texas Commission in fuel reconciliation proceedings.
On August 31, 2007, the Company filed for authority to reconcile its eligible fuel expenses and revenues for the period of March 1, 2004 through February 28, 2007 (Reconciliation Period), which was assigned PUC Docket No. 34695. The Company is seeking to reconcile a total of $548.4 million in eligible fuel, fuel-related, and purchased power expenses to generate and purchase electric energy for its Texas retail customers. At the conclusion of the Reconciliation Period, the Company had a cumulative under-recovery of such expenses of $18.2 million of which $17.6 million was subject to an existing fuel surcharge. The Company is seeking to carry over the cumulative Reconciliation Period fuel under-recovery balance into the subsequent reconciliation period beginning March 2007. Hearings on the fuel reconciliation are scheduled in May 2008. A final order is not expected to be issued until the third quarter of 2008.
On January 8, 2008, the Company filed a request with the Texas Commission to surcharge approximately $30.1 million of under-recovered fuel and purchased power costs and interest over a twelve month period beginning in March 2008. The fuel under-recoveries were incurred during the period December 2005 through November 2007. A decision from the Texas Commission is expected in the first quarter of 2008.
On January 5, 2006, the Company filed a petition (PUC Docket No. 32240) with the Texas Commission to increase its fixed fuel factors and to surcharge under-recovered fuel costs. The Company requested an increase in its Texas jurisdiction fixed fuel factors of $30.8 million or 16% annually to reflect an average cost of natural gas of $9.35 per MMBtu. The Company also requested a fuel surcharge to recover over a twelve-month period approximately $34 million of fuel undercollections, including interest, for under-recoveries for the period September 2005 through November 2005. The requested fuel factor and fuel surcharge were placed into effect on an interim basis subject to refund effective with February 2006 bills to customers. This proceeding was abated pending the Texas Commissions decision in the margin sharing proceeding, PUC Docket No. 32289, which was approved December 8, 2006. The Company filed a unanimous settlement with the Texas Commission to resolve all issues in this docket on January 24, 2007. The settlement provided for approval of the fuel surcharge and fuel factor for the period February 2006 through January 2007, the end of the surcharge period. In addition, the Company agreed to reduce its fixed fuel factors by 10% effective February 1, 2007 reducing annual fuel recoveries by approximately $20.0 million per year. The revised fixed fuel factors reflect natural gas prices of approximately $7.80 per MMBtu. A final order approving the settlement in PUC Docket No. 32240 was issued by the Texas Commission on March 15, 2007.
Generation CCN Filing. On July 6, 2007, the Company filed a petition with the Texas Commission requesting a Certificate of Convenience and Necessity (CCN) for two generating facilities in PUC Docket No. 34494. The first such facility is a natural-gas fueled power generating unit to be located at an existing plant site in El Paso. This facility is known as Newman Unit 5. The Newman Unit 5 project consists of 280 to 290 MW of natural gas-fired combined cycle generating capacity that the Company presently plans to construct in two phases. The first phase includes two 70 MW gas turbines to be installed by the peak of 2009. The second phase converts the unit into a combined cycle combustion turbine with a total capacity of 280 to 290 MW and is expected to be completed by late 2010 or early 2011.
The Newman Unit 5 will operate mostly in a baseload manner, but can also be used in a load following manner. It will be the most efficient gas-fired unit on the Companys system when operated in combined cycle. The total estimated cost of the project including allowance for funds used during construction is $245 million.
The Company also requested a CCN for two renewable energy wind turbines currently operating at the Hueco Mountains Wind Ranch, the acquisition of which the Texas Commission had previously found to be consistent with the public interest.
On December 17, 2007, the parties to PUC Docket No. 34494 filed a Stipulation, signed by all parties, which recommended approval of the Companys requests. On January 31, 2008, the Texas Commission issued an order approving the requested CCNs. The costs of the project have not been approved.
Palo Verde Performance Standards. The Texas Commission established performance standards for the operation of Palo Verde pursuant to which each Palo Verde unit is evaluated annually to determine whether its three-year rolling average capacity factor entitles the Company to a reward or subjects it to a penalty. The capacity factor is calculated as the ratio of actual generation to maximum possible generation. If the capacity factor, as measured on a station-wide basis for any consecutive 36-month period, should fall below 52.5%, the parties to the Texas Rate Agreements can seek different rate treatment for Palo Verde. The removal of Palo Verde from rate base could have a significant negative impact on the Companys revenues and financial condition. The Company has calculated the performance rewards for the reporting periods ending in 2007 and 2006 to be approximately $0.6 million and $0.4 million, respectively. The 2006 reward was included along with energy costs incurred and fuel revenue billed as part of the Texas Commissions review during the 2007 fuel reconciliation proceeding as discussed above. Under the performance standards the Company did not earn a performance reward nor incur a penalty for the 2005 reporting period. Performance rewards are not recorded on the Companys books until the Texas Commission has ordered a final determination in a fuel proceeding or comparable evidence of collectibility is obtained. Performance penalties would be recorded when assessed as probable by the Company.
In a prior fuel reconciliation proceeding (PUC Docket No. 20450), the Company agreed to contribute any Palo Verde rewards in its next fuel reconciliation to assist low-income customers in paying their utility bills. In compliance with the Texas Commissions order, the Company sought and received approval by the El Paso City Council in January 2006 to remit to El Paso approximately $5.8 million in Palo Verde performance reward funds to fund demand side management programs such
as weatherization with a focus on programs to assist small business and commercial customers. As of December 31, 2007 $5.6 million, including accrued interest, remains to be paid under these agreements and is recorded as a liability on the Companys balance sheet.
Deregulation. The Texas Restructuring Law required certain investor-owned electric utilities to separate power generation activities and retail service activities from transmission and distribution activities by January 1, 2002, and on that date, retail competition for generation services was instituted in some parts of Texas. However, the Texas Commission has delayed retail competition in the Companys Texas service territory by approving a rule which identifies various milestones for the Company to reach before competition can begin. The first milestone calls for the development, approval by the FERC, and commencement of independent operation of a regional transmission organization (RTO) in the area that includes the Companys service territory, including the development of retail market protocols to facilitate retail competition (see FERC Regulatory Matters RTO below). The complete transition to retail competition would occur upon the completion of the last milestone, which would be the Texas Commissions final evaluation of the markets readiness to offer fair competition and reliable service to all retail customers. The Company believes this rule delays retail competition in El Paso indefinitely. There is substantial uncertainty about both the regulatory framework and market conditions that will exist if and when retail competition is implemented in the Companys service territory, and the Company may incur substantial preparatory, restructuring and other costs that may not ultimately be recoverable. There can be no assurance that deregulation would not adversely affect the future operations, cash flows and financial condition of the Company.
Renewable Energy Requirements. Notwithstanding the Texas Commissions approval of a rule further delaying competition in the Companys Texas service territory, the Company became subject to the renewable energy and energy efficiency requirements of the Texas Restructuring Law on January 1, 2006. Under the renewable energy requirements, the Company is required to annually obtain its pro rata share of renewable energy credits as determined by the Program Administrator (the Electric Reliability Council of Texas). The Companys ultimate obligation to obtain renewable energy credits will not be known until January 31 of the year following the compliance year, and it will have until March 31 to obtain, if necessary, and submit to the Program Administrator, sufficient credits. The Company obtained the required renewable energy credits to meet its expected obligations through 2007.
2007 Energy Efficiency Legislation. New energy efficiency legislation was approved in Texas in June 2007. The new legislation establishes new and increased goals for additional cost-effective energy efficiency for residential and commercial customers equivalent to at least (i) 10% of the annual growth in peak demand for residential and commercial customers by December 31, 2007; (ii) 15% of the annual growth in demand by December 31, 2008; and (iii) 20% of the annual growth in demand by December 31, 2009. Among other things, the new legislation requires the Texas Commission to establish an energy efficiency cost recovery factor for ensuring cost recovery for utility expenditures made to satisfy the energy efficiency goal. The legislation provides that utilities that are unable to establish an energy efficiency cost recovery factor in a timely manner due to a rate freeze will be allowed to defer the costs of complying with the energy efficiency goal and recover such deferred costs at the end of the rate freeze period.
New Mexico Regulatory Matters
2007 New Mexico Stipulation. On July 3, 2007, the NMPRC issued a final order approving a stipulation (2007 New Mexico Stipulation) addressing all issues in the 2006 rate filing in Case No. 06-00258-UT. On July 26, 2007, the NMPRC modified its final order to clarify that its approval of the Stipulation did not preclude the NMPRC from examining the Companys rates upon its own motion at any time prior to the date stipulated for the Companys next rate filing. The 2007 New Mexico Stipulation provides for a $5.8 million non-fuel base rate increase and a $0.3 million fuel and purchased power decrease relative to test year rates. The 2007 New Mexico Stipulation reflects average natural gas costs of $7.20 per MMBtu for the June 2007 through May 2008 forecast period. Most of the Companys fuel and purchased power costs during the period of the 2007 New Mexico Stipulation are expected to be recovered through base rates. Any difference between actual fuel and purchased power costs and the amount included in base rates will be recovered or refunded through the Fuel and Purchased Power Cost Adjustment Clause (FPPCAC). Rates will continue in effect until changed by the NMPRC after the Companys next rate case. The 2007 New Mexico Stipulation requires the Company to file its next general rate case no later than May 30, 2009 using a base period of the twelve months ending December 31, 2008. Under NMPRC statutes, new rates would become effective no later than June 2010.
The 2007 New Mexico Stipulation provides for energy from the deregulated Palo Verde Unit 3 to be recovered through fuel and purchased power costs based upon the contract cost of capacity and fuel for power purchased under the existing SPS purchased power contract. The 2007 New Mexico Stipulation eliminates the fixed fuel and purchased power cost of $0.021 per kWh for 10% of New Mexico kWh sales and requires 25% of jurisdictional off-system sales margins to be credited to customers through the FPPCAC. Consistent with the Texas settlement in PUC Docket No. 32289, beginning in July 2010 through June 2015, the Company will credit 90% of the New Mexico jurisdictional portion of off-system sales margins to New Mexico customers through the FPPCAC. No later than two years after implementation, the 2007 New Mexico Stipulation requires the Company to file to continue its FPPCAC according to NMPRC rules, at which time any party may propose to change the price of capacity and related energy from Palo Verde Unit 3 since the SPS purchased power contract will terminate in September 2009. The 2007 New Mexico Stipulation results in final reconciliation of fuel and purchased power costs for the period May 31, 2004 through December 31, 2005. The Company will continue to file annual reconciliation statements for fuel and purchased power costs in accordance with NMPRC rules. The Company filed a reconciliation statement for the period June 1, 2006 through May 31, 2007 on August 31, 2007.
Fuel and Purchased Power Costs. The Company currently recovers fuel and purchased power costs in base rates in an average amount of $0.04288 per kWh and recovers the remaining fuel and purchased power costs through its FPPCAC. See discussion of 2007 New Mexico Stipulation above.
Notice of Investigation of Rates. On August 3, 2007, the Company received by mail a Notice of Investigation of Rates of El Paso Electric Company from the NMPRC in Case No. 07-00317-UT (the Notice). On August 21, 2007, the NMPRC requested the Company to file a response to the issues, including the reasonableness of fuel and purchased power costs. On September 7, 2007, the Company filed its response and requested that the NMPRC suspend its investigation and close the docket. No further
action has been taken by the Commission. The Company is unable at this time to predict any potential negative financial impact from this docket.
Renewables. The New Mexico Renewable Energy Act of 2004 as amended by the 2007 New Mexico legislature requires that, by January 1, 2006, renewable energy comprise no less than 5% of the Companys total retail sales to New Mexico customers. This requirement has been fixed at 6% until January 1, 2011, when the renewable portfolio standard increases to 10% of the Companys total retail sales to New Mexico customers. After 2011, the renewable portfolio standard, as a percentage of total retail sales to New Mexico customers, increases to 15% by 2015 and 20% by 2020. The Company has met all requirements to date.
The NMPRC approved the Companys 2006 annual procurement plan (Procurement Plan) in December 2006, including the purchase of renewable energy certificates (RECs) and the issuance of a diversity RFP for renewable resources to meet future requirements. In addition, the NMPRC authorized the Company to enter into two 20-year purchased power agreements to purchase energy from an 8 MW low-emissions biomass generating facility and from a 6 kW solar energy generating facility. Both generating facilities would have been located within the Companys New Mexico service area. The biomass renewable supplier defaulted on its contract obligations. In the Order approving the 2006 Plan, the NMPRC approved recovery of REC costs, without associated energy, through the FPPCAC. The NMPRCs decision to allow recovery of REC costs, without associated energy, through the FPPCAC was appealed to the New Mexico Supreme Court (the Court) by the New Mexico Industrial Energy Consumers. The Court issued a decision on August 28, 2007, ordering that RECs without associated energy could not be recovered through the FPPCAC, but the costs would be recovered through the ratemaking process. The Company filed a request to create a deferral as provided under New Mexico law, with carrying costs, to recover these costs and refunded to customers the previously-collected REC costs recovered through the FPPCAC. NMPRC action to approve the deferral, with carrying costs, is pending.
The Company filed its 2007 annual Procurement Plan on August 31, 2007. The Company has proposed procurement of Texas RECs to complete its 2008 and 2009 renewable obligations. The Company also requested funding to conduct a proposal process in 2008 to attempt to procure diverse renewable energy resources to meet NMPRC requirements. The Company is seeking a deferral of the costs associated with renewable compliance, including carrying costs. Hearings were held on November 29, 2007. The Hearing Examiner issued the Recommended Decision on December 5, 2007 recommending that the Companys request to replace the biomass project with Texas RECs be rejected and that the Company include a plan to replace these RECs with New Mexico RECs in its next procurement plan filing. The Company filed exceptions to the Recommended Decision on December 14, 2007. A NMPRC order adopting the Recommended Decision was issued on February 27, 2008.
New Mexico Energy Efficiency Plan Filing. On November 5, 2007, the Company filed its Application for Approval of Energy Efficiency and Load Management Programs. This case has been designated as NMPRC Case No. 07-00411-UT. In this filing, the Company requests approval of a number of energy efficiency programs. The Company also proposed a methodology to address disincentives and barriers to utility-provided energy efficiency and proposed to recover the costs of energy efficiency programs through a cost recovery factor. The hearing is scheduled to begin March 19, 2008. The final order is expected in June 2008.
New Mexico Energy Efficiency Legislation. On February 12, 2008, the New Mexico legislature passed House Bill 305, the Utility Customer Load Management bill. This bill modifies the 2005 Efficient Use of Energy Act and requires that electric utilities provide cost-effective energy efficiency programs that will produce savings of 5% of 2005 total retail kWh sales to New Mexico customers in calendar year 2014 and 10% of 2005 retail kWh sales to New Mexico customers in 2020. This legislation is expected to be signed by the governor.
2007 Long-Term Incentive Plan. On May 18, 2007, the Company filed for NMPRC approval for issuance of common stock for purposes of incentives and compensation. After the filing of supplemental testimony, the Hearing Examiner issued a Recommended Decision in July 2007 recommending that the securities transactions related to issuance of new stock be approved. The NMPRC requested additional supplemental testimony on the reasonableness of executive compensation and the effect on capital structure and rates to be set in the next general rate case. The Company filed supplemental testimony addressing these issues on October 31, 2007. Hearings on this matter were held on November 9, 2007. The Company is awaiting a final decision by the NMPRC.
New Mexico Investigation into Executive Compensation. In December 2007, the NMPRC initiated an investigation into executive compensation of investor-owned gas and electric public utilities. In its order initiating the investigation, the NMPRC required each utility to provide information on compensation of executive officers and directors for the period 1977-2006. The Company has provided the requested information. No further action has been taken by the NMPRC.
Generation CCN Filing. On July 18, 2007, the Company filed its application for issuance of a CCN to construct and operate Newman Unit 5. This case has been designated as NMPRC Case No. 07-00301-UT. The hearing was held on January 24, 2008. The Hearing Examiner issued a Recommended Decision on January 29, 2008 recommending Commission approval of the CCN. Pursuant to a request by the NMPRC, the Commission Staff and the Company provided additional information on February 26, 2008. A final order is expected in April 2008.
Federal Regulatory Matters
Transmission Dispute with Tucson Electric Power Company (TEP). In January 2006, the Company filed a complaint with the FERC to interpret the terms of a Power Exchange and Transmission Agreement (the Transmission Agreement) entered into with TEP in 1982. TEP filed a complaint with the FERC one day later raising virtually identical issues. TEP claimed that, under the Transmission Agreement, it was entitled to up to 400 MW of firm transmission rights on the Companys transmission system that would enable it to transmit power from a new generating station (the Luna Energy Facility (LEF) located near Deming, New Mexico) to Springerville or Greenlee in Arizona. The Company asserted that TEPs rights under the Transmission Agreement do not include transmission rights necessary to transmit such power as contemplated by TEP and that TEP must acquire any such rights in the open market from the Company at applicable tariff rates or from other transmission providers. On April 24, 2006, the FERC ruled in the Companys favor, finding that TEP does not have the transmission rights under the Transmission Agreement to transmit power from the LEF to Arizona. The ruling was based on written evidence presented and without an evidentiary hearing. TEPs request for a rehearing of the FERCs decision was granted in part and denied in part in an order issued October 4, 2006. The
October 4 order granted a hearing to examine the disputed evidence, and a hearing before an administrative law judge on the dispute was held on May 22 through May 24, 2007 and June 20, 2007.
The initial decision of the administrative law judge was issued September 6, 2007. The Presiding Judge generally found that the Transmission Agreement allows TEP to transmit power from the Deming Plant to Arizona but limits that transmission to 200 MW on any segment of the circuit and to non-firm service on the segment from Luna to Greenlee. The Company and TEP filed briefs on exceptions and replies to briefs on exceptions to the Initial Decision. In its brief on exceptions, TEP argued that it is entitled to a refund of the revenues the Company has received from TEP for transmission service to the Deming Plant during the pendency of these proceedings. In its response, the Company vigorously contested TEPs request for refunds. The Commission will issue a decision on the merits after review of the Initial Decision and the briefs on exceptions and replies to exceptions. While the Company believes that it will prevail on all points, the Company cannot predict the outcome of this case. During 2006 and 2007, TEP paid the Company $6.6 million for transmission service relating to the LEF. The Company has established a reserve for rate refund for $3.5 million related to this issue. If the FERC were to rule in TEPs favor, the Company may be required to refund all of the $6.6 million it has received from TEP for transmission service relating to the LEF and may lose the opportunity to receive compensation from TEP for such transmission service in the future. An adverse ruling by the FERC could have a negative effect on the Companys results of operations.
RTOs. FERCs rule on RTOs (Order 2000) strongly encourages, but does not require, public utilities to form and join RTOs. The Company is an active participant in the development of WestConnect. The Company has entered into a Memorandum of Understanding (MOU) with ten other transmission owners that obligates the parties to participate in and commit resources to ongoing joint efforts, including involvement with stakeholders, customers, local, state and federal regulatory personnel, and other Western Grid transmission providers to identify, develop and implement cost-effective wholesale market enhancements on a voluntary, phased-in basis to add value in transmission accessibility, wholesale market efficiency and reliability for wholesale users of the Western Grid. These enhancements may ultimately include formation of an RTO. WestConnect will continue to work with the FERC and two other proposed RTOs in the west to achieve a seamless market structure. The Company comprises approximately 7% of WestConnect and cannot control the terms or timing of its development. WestConnect as an RTO will not be operational for several years.
Department of Energy. The DOE regulates the Companys exports of power to the CFE in Mexico pursuant to a license granted by the DOE and a presidential permit. The DOE has determined that all such exports over international transmission lines shall be made in accordance with Order No. 888, which established the FERC rules for open access.
The DOE is authorized to assess operators of nuclear generating facilities a share of the costs of decommissioning the DOEs 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 Companys 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 grant license extensions pursuant to the Atomic Energy Act of 1954, as amended.
Sales for Resale
The Company entered into a contract to sell up to 100 MW firm energy and 50 MW of contingent energy to Imperial Irrigation District (IID) which began May 1, 2007 and continues through April 30, 2009. The contract also provides for the Company to sell up to 100 MW firm energy and 40 MW of contingent energy beginning May 1, 2009 through April 30, 2010. To ensure that power is available to meet the IID contract demand, the Company entered into a contract effective May 1, 2007 to purchase up to 100 MW of firm energy from CreditSuisse Energy, LLC. This contract provides for firm energy to be delivered at Palo Verde through April 30, 2010 and/or 50 MW of energy delivered at Four Corners in the months of July through September 2007 and May through September for the years 2008 through 2010.
The Company provides up to 10 MW of firm capacity, associated energy, and transmission service to the Rio Grande Electric Cooperative pursuant to an ongoing contract which requires a two-year notice to terminate. In 2006 the Company provided RGEC with a notice of termination. Such termination will be effective as of March 31, 2008. The Company is discussing the provision of future electric service with RGEC.
Power Sales Contracts
The Company has entered into several short-term (three months or less) off-system sales contracts for the first quarter of 2008. The Company has also entered into other longer-term sales for which the supply is fully hedged.
Franchises and Significant Customers
El Paso Franchise
The Company has a franchise agreement with El Paso, the largest city it serves, through July 31, 2030. The franchise agreement includes a franchise fee of 3.25% of revenues and allows the Company to utilize public rights-of-way necessary to serve its retail customers within El Paso.
Las Cruces Franchise
In February 2000, the Company and Las Cruces entered into a seven-year franchise agreement with a franchise fee of 2% of revenues (approximately $1.5 million per year) for the provision of electric distribution service. Las Cruces exercised its right to extend the franchise for an additional two-year term ending April 30, 2009 and waived its option to purchase the Companys distribution system pursuant to the terms of the February 2000 settlement agreement.
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 Companys sales to the military bases represent approximately 2% of annual operating revenues. The Company signed a contract with Ft. Bliss in December 1998 under which Ft. Bliss will take retail electric service from the Company through December 2008. In May 1999, the Army and the Company entered into a ten-year contract to provide retail electric service to White Sands. In March 2006, the Company signed a contract with Holloman that provides for the Company to provide retail electric service and limited wheeling services to Holloman for a ten-year term which expires in January 2016.
Like other companies in our industry, our consolidated financial results will be impacted by weather, the economy of our service territory, market prices for power, fuel prices, and the decisions of regulatory agencies. Our common stock price and creditworthiness will be affected by local, regional and national macroeconomic trends, general market conditions and the expectations of the investment community, all of which are largely beyond our control. In addition, the following statements highlight risk factors that may affect our consolidated financial condition and results of operations. These are not intended to be an exhaustive discussion of all such risks, and the statements below must be read together with factors discussed elsewhere in this document and in our other filings with the SEC.
Our Costs Could Increase or We Could Experience Reduced Revenues if
There are Problems at the Palo Verde Nuclear Generating Station
A significant percentage of our generating capacity, off-system sales margins, assets and operating expenses is attributable to Palo Verde. Our 15.8% interest in each of the three Palo Verde units totals approximately 633 MW of generating capacity. Palo Verde represents approximately 42% of our available net generating capacity and represented approximately 43% of our available energy for the twelve months ended December 31, 2007. Palo Verde comprises 41% of our total net plant-in-service and Palo Verde expenses comprise a significant portion of operation and maintenance expenses. APS is the operating agent for Palo Verde, and we have limited ability under the ANPP Participation Agreement to influence operations and costs at Palo Verde. Palo Verde operated at a capacity factor of 78.5% and 70.4% in the twelve months ended December 31, 2007 and 2006, respectively.
The NRC has placed Palo Verde Unit 3 in the multiple repetitive degraded cornerstone column of its action matrix which results in an enhanced NRC inspection regimen. We face the risk of additional or unanticipated costs at Palo Verde resulting from (i) increases in operation and maintenance expenses, including additional costs relating to the enhanced NRC oversight; (ii) increases in the cost of uranium; (iii) the replacement of reactor vessel heads at the Palo Verde units; (iv) an extended outage of any of the Palo Verde units; (v) increases in estimates of decommissioning costs; (vi) the storage of radioactive waste, including spent nuclear fuel; (vii) prolonged reductions in generating output; (viii) insolvency of other Palo Verde Participants; and (ix) compliance with the various requirements and regulations governing commercial nuclear generating stations.
Our ability to increase retail base rates in Texas is limited through June 2010. We cannot seek approval to increase our base rates in Texas in the event of increases in non-fuel costs or loss of revenue unless our return on equity falls below the bottom of a defined range which currently is approximately 8.3%. Our rates in New Mexico will be fixed until after the conclusion of the May 2009 rate filing. We cannot assure that 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.
We May Not Be Able to Recover All of Our Fuel Expenses from Customers
In general, by law, we are entitled to recover our prudently incurred fuel and purchased power expenses from our customers in Texas and New Mexico. The 2007 New Mexico Stipulation provides for energy from the deregulated Palo Verde Unit 3 to be recovered through fuel and purchased power costs based upon the contract cost of capacity and fuel for power purchased under the existing SPS purchased power contract. The 2007 New Mexico Stipulation requires the Company to file its FPPCAC according to NMPRC rules, at which time any party may propose to change the price of capacity and related energy from Palo Verde Unit 3 after the SPS purchased power contract is terminated September 30, 2009. The fuel expense in New Mexico and Texas is subject to reconciliation by the Texas Commission and the NMPRC. Prior to the completion of a reconciliation, we record fuel and purchased power costs transactions such that fuel revenues equal fuel and purchased power expense including the repriced energy costs for Palo Verde Unit 3 in New Mexico. In the event that a disallowance occurs during a reconciliation proceeding, the amounts recorded for fuel and purchased power expenses could differ from the amounts we are allowed to collect from our customers and we would incur a loss to the extent of the disallowance.
In New Mexico, the FPPCAC allows us to reflect current fuel and purchased power expenses in the FPPCAC and to adjust for under-recoveries and over-recoveries with a two-month lag. In Texas, fuel costs are recovered through a fixed fuel factor that may be adjusted two times per year. If we materially under-recover fuel costs, we may seek a surcharge to recover those costs at the time of the next fuel factor filing. During periods of significant increases in natural gas prices such as occurred in 2005, the Company realizes a lag in the ability to reflect increases in fuel costs in its fuel recovery mechanisms. As a result, cash flow is impacted due to the lag in payment of fuel costs and collection of fuel costs from customers. At December 31, 2007 and December 31, 2006, the Company had deferred fuel balances of $27.7 million and $32.6 million, respectively. To the extent the fuel and purchased power recovery processes in Texas and New Mexico do not provide for the timely recovery of such costs, we could experience a material negative impact on our cash flow.
Equipment Failures and Other External Factors Can Adversely Affect Our Results
The generation and transmission of electricity require the use of expensive and complex equipment. While we have a maintenance program in place, generating plants are subject to unplanned outages because of equipment failure. We are particularly vulnerable to this due to the advanced age of several of our gas-fired generating units in or near El Paso. In addition, we are seeking to extend the lives of these plants. In the event of unplanned outages, we must acquire power from others at unpredictable costs in order to supply our customers and comply with our contractual agreements. This can materially increase our costs and prevent us from selling excess power at wholesale, thus reducing our profits. In addition, actions of other utilities may adversely affect our ability to use transmission lines to deliver or import power, thus subjecting us to unexpected expenses or to the cost and uncertainty of public policy initiatives. We are particularly vulnerable to this because a significant portion of our available energy (at Palo Verde and Four Corners) is located hundreds of miles from El Paso and Las Cruces and must be delivered to our customers over long distance transmission lines. In addition, Palo Verdes availability is an important factor in realizing off-system sales margins. These factors, as well as weather, interest rates, economic conditions, fuel prices and price volatility, are largely beyond our control, but may have a material adverse effect on our consolidated earnings, cash flows and financial position.
We May Not Be Able To Recover All Costs of New Generation
We have obtained from the Texas Commission, and have pending with the NMPRC, CCNs to construct a new generating unit (Newman Unit 5) in El Paso to meet our expected customers demand for electricity. We have provided the estimated cost of constructing Newman Unit 5 to the Texas Commission and NMPRC. We have risks associated with completing the construction of Newman Unit 5 on time and within projected costs. In addition, we have risks associated with obtaining financing for Newman Unit 5 at reasonable rates as we expect to issue debt to finance a portion of the plant.
The cost of financing and constructing Newman Unit 5 will be reviewed in future rate cases in both Texas and New Mexico. To the extent that the Texas Commission or NMPRC determines that the costs of construction are not reasonable because of cost overruns, delays or other reasons, we may not be allowed to recover these costs from customers in base rates.
In addition, if the unit is not completed on time, we may be required to purchase power or operate less efficient generating units to meet customer requirements. Any replacement purchased power or fuel costs will be subject to regulatory review by the Texas Commission and NMPRC. We face financial risks to the extent that recovery is not allowed for any replacement fuel costs resulting from delays in the completion of Newman Unit 5.
Competition and Deregulation Could Result in a Loss of Customers and Increased Costs
As a result of changes in federal law, our wholesale and large retail customers already have, in varying degrees, alternate sources of power, including co-generation of electric power. Deregulation legislation is in effect in Texas requiring us to separate our transmission and distribution functions, which would remain regulated, from our power generation and energy services businesses, which would operate in a competitive market, in the future. In 2004, the Texas Commission approved a rule delaying retail competition in our Texas service territory. This rule identified various milestones that we must reach before retail competition can begin. The first milestone calls for the development, approval by the FERC, and commencement of independent operation of an RTO in the area that includes our service territory. This and other milestones are not likely to be achieved for a number of years. There is substantial uncertainty about both the regulatory framework and market conditions that would exist if and when retail competition is implemented in our Texas service territory, and we may incur substantial preparatory, restructuring and other costs that may not ultimately be recoverable. There can be no assurance that deregulation would not adversely affect our future operations, cash flows and financial condition.
Executive Officers of the Registrant
The executive officers of the Company as of February 15, 2008, were as follows:
The executive officers of the Company are elected annually and serve at the discretion of the Board of Directors.
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.
In July 2007, the Company entered into an agreement to lease executive and administrative offices in El Paso, Texas under a lease which expires in May 2018 with three concurrent renewal options of five years each. On February 8, 2008, the Company exercised its right of first refusal in the lease agreement to purchase this office building. All obligations previously incurred relating to this lease were terminated.
In addition, the Company leases certain warehouse facilities in El Paso, Texas under a lease which expires in December 2009 with three concurrent renewal options of one year each. The Company also has several other leases for office and parking facilities which expire within the next six years.
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, to the extent that the Company has been able to reach a conclusion as to its ultimate liability, it believes that none of these claims will have a material adverse effect on the financial position, results of operations or cash flows of the Company.
On June 7, 2004, the City of Tacoma filed suit against the Company and other defendants in the United States District Court for the Western District of Washington (City of Tacoma v. American Electric Power Service Corp., et al., C04-5325RBL). This complaint sought civil damages (including treble damages) from the Company and the other defendants for violations of certain antitrust provisions under the Sherman Act. This matter was filed in the United States District Court for the Western District of Washington and on February 11, 2005, the Court granted the Companys motion to dismiss the case. The City of Tacoma filed a notice of appeal with the U.S. Court of Appeals for the Ninth Circuit. On March 20, 2007, the Ninth Circuit entered an order dismissing the appeal pursuant to a stipulation of the parties. The dismissal is final and no further appeal may be filed.
On May 5, 2004, Wah Chang, a specialty metals manufacturer which operates a plant in Oregon, filed suit against the Company and other defendants in the United States District Court for the District of Oregon. (Wah Chang v. Avista Corporation, et al., No. 04-619AS). The complaint also makes substantially the same allegations as were made in City of Tacoma and seeks the same types of damages. This matter was transferred to the same court that heard and dismissed the City of Tacoma lawsuit and on February 11, 2005, the Court granted the Companys motion to dismiss the case. Wah Chang filed notice of appeal with the U.S. Court of Appeals for the Ninth Circuit, and in November 2007, the Ninth Circuit upheld the dismissal of the suit. Wah Chang filed a motion for rehearing of the appeal, and on January 15, 2008, the Ninth Circuit denied Wah Changs motion. While the Company believes that this matter is without merit and intends to defend itself vigorously in any further appeal by Wah Chang to the U.S. Supreme Court, the Company is unable to predict the outcome or range of possible loss.
See Regulation for discussion of the effects of government legislation and regulation on the Company.
No matter was submitted to vote of the Companys security holders through the solicitation of proxies or otherwise during the fourth quarter of 2007.
The Companys common stock trades on the New York Stock Exchange under the symbol EE. The high, low and close sales prices for the Companys common stock, as reported in the consolidated reporting system of the New York Stock Exchange for the periods indicated below were as follows:
The following graph compares the performance of the Companys Common Stock to the performance of the NYSE Composite, and the Edison Electric Institutes Index of investor-owned electric utilities setting the value of each at December 31, 2002 to a base of 100. The table sets forth the relative yearly percentage change in the Companys cumulative total shareholder return as compared to the NYSE, and the EEI, as reflected in the graph.
As of January 31, 2008, there were 3,856 holders of record of the Companys common stock. The Company does not anticipate paying dividends on its common stock in the near-term. The Company intends to continue its stock repurchase programs with the goal of managing its capital structure and enhancing shareholder value.
Since the inception of the stock repurchase programs in 1999, the Company has repurchased a total of approximately 19.3 million shares of its common stock at an aggregate cost of $269.4 million, including commissions. In September 2006, the Board of Directors (the Board) authorized the repurchase of up to 2.3 million shares of the Companys outstanding common stock (the 2006 Plan). During 2006 and 2007, the Company repurchased 4,005,158 shares of common stock under the 2006
Plan and under a previous plan approved by the Board in 2004 (the 2004 Plan) at an aggregate cost of $93.8 million. As of December 31, 2007, no shares remain available under the 2006 Plan or the 2004 Plan. In November 2007, the Board authorized the repurchase of up to an additional 2 million shares of the Companys outstanding common stock (the 2007 Plan). No shares have been repurchased under the 2007 Plan. The Company may in the future make purchases of its common stock pursuant to the 2007 Plan in open market transactions at prevailing prices and may engage in private transactions where appropriate. The repurchased shares will be available for issuance under employee benefit and stock incentive plans, or may be retired.
For Equity Compensation Plan Information see Part III, Item 12 Security Ownership of Certain Beneficial Owners and Management.
As of and for the following periods (in thousands except for share data):
Certain amounts presented for prior years have been reclassified to conform to the 2007 presentation.
As you read this Managements Discussion and Analysis, please refer to our Consolidated Financial Statements and the accompanying notes, which contain our operating results.
Summary of Critical Accounting Policies and Estimates
Note A to the Consolidated Financial Statements contains a summary of significant accounting policies. The preparation of our financial statements requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and related notes for the periods presented and actual results could differ in future periods from those estimates. Critical accounting policies and estimates are both important to the portrayal of our financial condition and results of operations and require complex, subjective judgments and include the following:
Application of SFAS No. 71
The Company applies the provisions of Statement of Financial Accounting Standards No. 71, Accounting for the Effects of Certain Types of Regulation, (SFAS No. 71) to its regulated operations in Texas and New Mexico. SFAS No. 71 requires a rate regulated enterprise to reflect the economic impact of regulatory decisions in its financial statements. As a result, we record certain costs or obligations as either assets or liabilities on our balance sheet and amortize them in subsequent periods. The deferral of costs as regulatory assets is appropriate only when the future recovery of such costs is probable. The application of SFAS No. 71 requires our management to make assumptions and estimates as to the amount of costs that regulatory authorities will ultimately permit us to recover. In the event we determine that we can no longer apply SFAS No. 71 to all or a portion of our operations, either as (i) a result of the establishment of retail competition in our service territory; (ii) a change in the regulatory approach for setting rates from cost-based ratemaking to another form of ratemaking; or (iii) other regulatory actions that restrict cost recovery to a level insufficient to recover costs, we could be required to record a charge against income in the amount of the remaining unamortized net regulatory assets. Such an action could materially reduce our shareholders equity.
As of December 31, 2006, we determined that we met the criteria to re-apply SFAS No. 71 to our Texas jurisdiction, and we recorded regulatory assets of $9.6 million and associated accumulated deferred tax liabilities of $3.5 million, representing costs currently being recovered through the Texas fuel factor, which resulted in an extraordinary gain of $6.1 million, net of tax. We determined it was not appropriate at this time to recognize other potential regulatory assets and liabilities, such as the costs associated with refinancing our first mortgage bonds in 2005, because in our judgment they have not yet been included in our recoverable cost of service. We had previously made a determination to re-apply SFAS No. 71 to our New Mexico jurisdiction beginning July 1, 2004. At December 31, 2007, we had $27.8 million of regulatory assets, net of regulatory liabilities. We may record additional regulatory assets and regulatory liabilities in the future based on our judgment as to whether sufficient evidence exists that our regulators will include them in our rate base and or cost of service. Thus, the amount of our net regulatory assets could increase materially in the future. In addition, we include an allowance for equity and borrowed funds used during construction as a cost of construction of electric plant in service. The allowance for equity funds used during construction is recognized as other income and the allowance for borrowed
funds used during construction is shown as capitalized interest in our statement of operations. Under this treatment, we report higher other income and lower capitalized interest expense than we would have reported prior to the re-application of SFAS No. 71, and the difference may be material if our construction program continues at current levels or should increase relative to current levels. The factors that supported our decision are set forth in Note A to the consolidated financial statements.
Collection of Fuel Expense
In general, by law and regulation, our fuel and purchased power expenses are recovered from our customers. In times of rising fuel prices, we experience a lag in recovery of higher fuel costs. These costs are subject to reconciliation by the Texas Commission and the NMPRC. Prior to the completion of a reconciliation, we record fuel transactions such that fuel revenues equal fuel expense except for the fixed portion in New Mexico prior to July 2007. In the event that a disallowance occurs during a reconciliation proceeding, the amounts recorded for fuel and purchased power expenses could differ from the amounts we are allowed to collect from our customers, and we could incur a loss to the extent of the disallowance.
Decommissioning Costs and Estimated Asset Retirement Obligation
Pursuant to the ANPP Participation Agreement and federal law, we must fund our share of the estimated costs to decommission Palo Verde Units 1, 2 and 3 and associated common areas. We recorded a liability and a corresponding asset for the fair value of our decommissioning obligation upon implementation of SFAS No. 143, Accounting for Asset Retirement Obligations. We will adjust the liability to its present value periodically over time, and the corresponding asset will be depreciated over its useful life. The determination of the estimated liability requires the use of various assumptions pertaining to decommissioning costs, escalation and discount rates.
We and other Palo Verde Participants rely upon decommissioning cost studies and make discount rate, rate of return and inflation projections to determine funding requirements and estimate liabilities related to decommissioning. Every third year outside engineers perform a study to estimate decommissioning costs associated with Palo Verde Units 1, 2 and 3 and associated common areas. We determine how we will fund our share of those estimated costs by making assumptions about future investment returns and future decommissioning cost escalations. The funds are invested in professionally managed investment trust accounts. We are required to establish a minimum accumulation and a minimum funding level in our decommissioning trust accounts at the end of each annual reporting period in accordance with the ANPP Participation Agreement. If actual decommissioning costs exceed our estimates, we would incur additional costs related to decommissioning. Further, if the rates of return earned by the trusts fail to meet expectations, we will be required to increase our funding to the decommissioning trust accounts. Although we cannot predict the results of future studies, we believe that the liability we have recorded for our decommissioning costs will be adequate to fund our share of the costs, assuming that Palo Verde Units 1, 2 and 3 operate over their remaining lives (which includes an assessment of the probability of a license extension) and that the DOE assumes responsibility for permanent disposal of spent fuel at plant shut down. We believe that our current annual funding levels of the decommissioning trust will adequately provide for the cash requirements associated with decommissioning. Historically, regulated utilities like us have been permitted to collect in rates in Texas and New Mexico the costs of nuclear decommissioning. Should we become subject to the Texas Restructuring Law, we will be able to collect from regulated transmission and distribution customers the costs of decommissioning. Reference is made to Note D, Accounting for Asset Retirement Obligations to the Notes to Consolidated Financial Statements.
Future Pension and Other Postretirement Obligations
Our obligations to retirees under various benefit plans are recorded as a liability on the consolidated balance sheets. Our liability is calculated on the basis of significant assumptions regarding discount rate, expected return on plan assets, rate of compensation increase and health care cost inflation. Our assumptions as well as a sensitivity analysis of the effect of hypothetical changes in certain assumptions are set forth in detail in Note K, Employee Benefits, to the Notes to Consolidated Financial Statements. Changes in these assumptions could have a material impact on both net income and on the amount of liabilities reflected on the consolidated balance sheets.
In developing the assumptions, management makes judgments based on the advice of financial and actuarial advisors and our review of third-party and market-based data. These sources include life expectancy tables, surveys of compensation and health care cost trends, and historical and expected return data on various categories of plan assets. The assumed discount rate applied to future plan obligations is based at each measuring date on prevailing market interest rates inherent in high quality (AA and better) corporate bonds that would provide future cash flow needed to pay the benefits as they become due, as well as on publicly available bond issues. We regularly review our assumptions and conduct a reassessment at least once a year. We do not expect that any such change in assumptions will have a material effect on net income for 2008.
Our federal tax returns for the years 1999 through 2004 have been examined by the IRS. On June 12, 2007, we received from the IRS a notice of proposed deficiency for the tax years 1999 through 2004. A previous IRS notice of proposed deficiency had been received in 2005 for the years 1999 through 2002. The primary audit adjustments proposed by the IRS related to (i) whether we were entitled to currently deduct payments related to the repair of the Palo Verde Unit 2 steam generators or whether these payments should be capitalized and depreciated and (ii) whether we were entitled to currently deduct payments related to the dry cask storage facilities for spent nuclear fuel or whether these payments should be capitalized and depreciated. A tax deficiency was also received proposing to include in taxable income capital costs paid by third parties for construction of a switchyard. The third parties have indemnified the Company against any tax liability associated with the switchyard. The proposed IRS adjustments would affect the timing of these deductions, not their ultimate deductibility for federal tax purposes. We have protested the audit adjustments through administrative appeals. We believe that our treatment of the payments is supported by substantial legal authority. The IRS is currently performing an examination of the 2005 income tax return. We review our accruals for future liabilities under the provisions of the FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes, (FIN 48). FIN 48 provides a recognition threshold and measurement attribute for the financial statement measurement of tax positions. We have evaluated our tax positions under these provisions including the recognition of interest and penalties on tax benefits that have not been recognized. Although the ultimate outcome of the appeals and current examination cannot be predicted with certainty, we believe that, as of December 31, 2007, we have adequately recognized our expected tax liabilities.
The following is an overview of our results of operations for the years ended December 31, 2007, 2006 and 2005. Income for the years ended December 31, 2007, 2006 and 2005 is shown below:
The following table and accompanying explanations show the primary factors affecting the after-tax change in income before extraordinary items and cumulative effect of accounting change between the calendar years ended 2007 and 2006, 2006 and 2005, and 2005 and 2004 (in thousands):
Historical Results of Operations
The following discussion includes detailed descriptions of factors affecting individual line items in the results of operations. The amounts presented below are presented on a pre-tax basis.
We realize revenue from the sale of electricity to retail customers at regulated rates and the sale of energy in the wholesale power market generally at market based prices. Sales for resale (which are wholesale sales within our service territory) accounted for less than 1% of revenues. Off-system sales are wholesale sales into markets outside our service territory. Off-system sales are primarily made in off-peak periods when we have competitive generation capacity available after meeting our regulated service obligations. Under the terms of our rate agreements in Texas and New Mexico, we share 25% of our off-system sales margins with customers in Texas and New Mexico (effective July 1, 2005 and July 1, 2007, respectively). We also share 25% of transmission wheeling revenues in Texas. (See Note B of the Notes to Consolidated Financial Statements).
Revenues from the sale of electricity include the recovery of fuel costs, which are recovered from our customers through fuel adjustment mechanisms in Texas and New Mexico and a portion through base rates in New Mexico. We record deferred fuel revenues for the difference between fuel costs and fuel revenues until such amounts are collected from or refunded to customers. Non-fuel base revenues refers to our revenues from the sale of electricity excluding such fuel costs.
Retail non-fuel base revenue percentages by customer class are presented below:
No retail customer accounted for more than 2% of our non-fuel base revenues during such periods. As shown in the table above, residential and small commercial customers comprise approximately 76% of our revenues. While this customer base is more stable, it is also more sensitive to changes in weather conditions. As a result, our business is seasonal, with higher kWh sales and revenues during the summer
cooling season. The following table sets forth the percentage of our revenues derived during each quarter for the periods presented:
Heating and cooling degree days can be used to evaluate the effect of weather on energy use. For each degree the average outdoor temperature varies from a standard of 65 degrees Fahrenheit a degree day is recorded. The table below, shows heating and cooling degree days compared to a 10-year average for 2007, 2006 and 2005.
Customer growth is a primary driver in our retail sales growth. The average number of retail customers grew 2.4% and 2.7% in 2007 and 2006, respectively. See the tables presented on pages 43 and 44 which provide detail on the average number of retail customers and the related revenues and kWh sales.
Retail non-fuel base revenues. Retail non-fuel base revenues increased by $18.6 million or 4.2% for the twelve months ended December 31, 2007 when compared to the same period in 2006 largely due to increased kWh sales associated with a 2.4% increase in the average number of retail customers served and colder winter weather in the first quarter of 2007 compared to the same period in 2006. Non-fuel base revenues to residential customers increased $8.9 million or 5.1% due to increased kWh sales. KWh sales to residential customers increased 5.6% in the twelve-month period compared to the same period last year largely as a result of a 2.1% increase in the average number of residential customers served and the colder winter weather in the first quarter of 2007. Heating degree days increased 13.2% while cooling degree days increased 2.2% for the twelve-month period in 2007 compared to the same period last year. Small commercial and industrial non-fuel base revenues increased $6.7 million or 4.2% in the twelve-month period ended December 31, 2007 reflecting an increase in kWh sales of 2.6% and a small increase in non-fuel base rates in New Mexico effective in July 2007. Other public authorities non-fuel base revenues increased $4.3 million or 6.3% due to a 3.1% increase in kWh sales and a small increase in non-fuel base rates in New Mexico. Large commercial and industrial non-fuel base revenues decreased $1.4 million or 3.5% primarily due to customers migrating to the small commercial and industrial class.
Retail non-fuel base revenues increased by $9.5 million or 2.2% for the twelve months ended December 31, 2006 when compared to the same period in 2005. Retail kWh sales in the twelve month period ended December 31, 2006 were 2.5% higher than the twelve month period ended December 31, 2005. Growth of 2.7% in the average number of retail customers served in 2006 accounted for most of the increase in sales. The mild weather in the first quarter of 2006 was largely offset by warmer summer weather in the second quarter of 2006. Cooling and heating degree days for the twelve months ended
December 31, 2006 were approximately 3.6% and 7.2% below 2005, respectively. As a result, retail non-fuel base revenues for the residential, small commercial and industrial and other public authorities customer classes increased primarily due to customer growth. Retail base revenues for large commercial and industrial increased primarily as a result of increased kWh sales to large industrial customers.
Fuel revenues. Fuel revenues consists of: (i) revenues collected from customers under fuel recovery mechanisms approved by the state commissions, (ii) deferred fuel revenues which are comprised of the difference between fuel costs and fuel revenues collected from customers and (iii) fuel costs recovered in base rates in New Mexico. In New Mexico, the fuel adjustment clause allows us to reflect current fuel costs above the amount recovered in base rates and to recover under-recoveries or refund over-recoveries with a two-month lag. Until terminated on July 1, 2007, a fixed amount of fuel costs was reflected in the fuel adjustment clause for 10% of kWh sales. In Texas, fuel costs are recovered through a fixed fuel factor that may be adjusted two times per year. In addition, if we materially over-recover fuel costs, we must seek to refund the over-recovery, and if we materially under-recover fuel costs, we may seek a surcharge to recover those costs.
In September 2007, we completed the recovery of $53.6 million of fuel under-recoveries through a fuel surcharge from our Texas customers which began in October 2005. We completed the recovery in January 2007 of $34 million of fuel under-recoveries, including interest through the surcharge period, through a fuel surcharge which began in February 2006. In 2007, 2006 and 2005, we collected $22.9 million, $56.9 million and $6.0 million of deferred fuel revenues in Texas through surcharges, respectively.
We under-collected current fuel costs and deferred for future recovery from our Texas and New Mexico customers by $17.8 million and $79.5 million in 2007 and 2005, respectively, compared to an over-collection of fuel costs of $3.7 million in 2006. At December 31, 2007, we had an under-recovered fuel balance of $29.2 million from our Texas customers and an over-recovery balance of $1.5 million from our New Mexico customers. At December 31, 2006, we had under-recovered fuel balances of $29.8 million from our Texas customers and $2.8 million from our New Mexico customers.
Off-system sales. Off-system sales are primarily made in off-peak periods when we have competitive generation capacity available after meeting our regulated service obligations. Typically, we realize between 40% and 50% of our off-system sales margins in the first quarter of each calendar year when our native load is lower than at other times of the year, allowing for the sale in the wholesale market of relatively larger amounts of off-system energy generated from lower cost generating resources. Palo Verdes availability is an important factor in realizing these off-system sales margins. The table below shows MWhs, sales revenue, fuel cost, total margins and retained margins made on off-system sales for the twelve months ended December 31, 2007, 2006 and 2005:
Off-system sales increased $30.0 million or 31.3% for the twelve months ended December 31, 2007 when compared to 2006 primarily due to increased off-system kWh sales of 34.6%. We had increased energy available for sale in the twelve months of 2007 compared to the same period in 2006 primarily due to the increased energy generated at Palo Verde in the first six months of 2007 compared to the same period in 2006. This increase was partially offset by lower average market prices. Customers receive 25% of off-system sales margins in Texas and New Mexico pursuant to rate settlements. Prior to July 1, 2007, we retained 100% of off-system sales margins in New Mexico.
Off-system sales increased $17.7 million or 22.7% for the twelve months ended December 31, 2006 when compared to 2005 primarily due to increased off-system kWh sales of 15.1% and higher average market prices.
Comparisons of kWh sales and operating revenues are shown below (in thousands):
Our sources of energy include electricity generated from our nuclear, natural gas and coal generating plants and purchased power. Palo Verde represented approximately 42% of our available net generating capability and approximately 43% of our available energy for the twelve months ended December 31, 2007.
Our energy expenses increased $47.3 million for the twelve months ended December 31, 2007 when compared to 2006 primarily due to (i) increased natural gas costs of $37.7 million due to increased natural gas-fired generation, (ii) increased costs of purchased power of $9.8 million due to higher market prices for power, and (iii) increased nuclear fuel costs of $2.8 million due to increased generation. These increases were partially offset in 2007 by a $2.7 million refund related to a gas pipeline reservation fee and a $0.4 million decrease to our coal expense due to a decrease in the amount of coal burned.
Energy expenses decreased $12.6 million for the twelve months ended December 31, 2006 when compared to 2005 due to decreased natural gas generation and lower natural gas prices. During 2006, we were able to displace gas-fired generation with increased purchases of economy energy in the wholesale power market. The average cost of purchased power in 2006 was $52.97 per megawatt-hour compared to our cost of generating power at our gas-fired generating plants of $78.91 per megawatt-hour. In addition, the average cost of purchased power in 2006 was approximately 17% lower than in 2005. As a result, we purchased 76% more energy in 2006 compared to 2005 which resulted in increased costs of purchased power of $37.0 million.
Other operations expense
Other operations expense increased $4.4 million, or 2.3% in 2007 compared to 2006 primarily due to increased Palo Verde operations expense of $9.0 million. This increase was partially offset by decreased administrative and general expenses of $5.6 million related to a decrease in workers compensation insurance costs, an increase in capitalized employee salaries and benefits, and a decrease in legal expenses related to regulatory matters.
Other operations expense increased $13.2 million, or 7.4% in 2006 compared to 2005 primarily due to (i) increased Palo Verde operation expense of $5.1 million; (ii) increased transmission expense of $2.7 million primarily as the result of new wheeling contracts; (iii) increased customer accounts expense of $1.8 million due to increased bad debt expense; (iv) increased accruals for employee incentive payments of $2.9 million; and (v) increased consulting fees of $1.8 million.
Maintenance expense decreased $3.1 million, or 5.1% in 2007 compared to 2006 due to decreased maintenance expense at our gas-fired generating plants of $5.6 million as a result of the timing of planned maintenance, partially offset by increased maintenance expense at Palo Verde of $2.3 million.
Maintenance expense increased $12.7 million, or 26.8% in 2006 compared to 2005 primarily due to increased maintenance expense at Palo Verde of $7.9 million and our gas-fired generating plants of $3.9 million.
Depreciation and amortization expense
Depreciation and amortization expense increased $1.0 million in 2007 compared to 2006 primarily due to increased depreciable plant balances. Depreciation and amortization expense decreased $14.0 million in 2006 compared to 2005 primarily due to completing the recovery of certain fresh-start accounting related assets over the term of a rate stipulation in Texas Docket No. 12700 which ended in July 2005. The decrease was partially offset by increases in the depreciable plant balances, primarily related to the replacement of Palo Verde Unit 1 steam generators in December 2005.
Taxes other than income taxes
Taxes other than income taxes decreased $1.3 million in 2007 compared to 2006 primarily due to a decrease in property taxes and the change in the Texas franchise (income) tax law in 2006 which took effect in 2007. These decreases were partially offset by an increase in payroll taxes. Taxes other than income taxes increased $5.5 million in 2006 compared to 2005 primarily due to an increase in the El Paso city franchise fees which took effect in August 2005 and higher taxable revenues due to increased kWh sales and increases in fuel recoveries including fuel surcharges. We incur city franchise taxes as revenues are billed to customers.
Other income (deductions)
Other income (deductions) increased $7.7 million for the twelve months ended December 31, 2007 compared to the same period last year primarily due to (i) increased allowance for equity funds used during construction (AEFUDC) due to the re-application of SFAS No. 71 to our Texas jurisdiction
beginning December 31, 2006 and increased construction work in progress subject to AEFUDC in 2007 and (ii) increased investment and interest income due to increased interest income on larger cash and decommissioning trust fund balances.
Other income (deductions) increased $20.8 million in 2006 compared to 2005 primarily due to a decrease in the loss on extinguishment of debt of $19.6 million, resulting from the retirement of our first mortgage bonds in the second quarter of 2005.
Interest charges (credits)
Interest charges (credits) decreased $1.3 million for the twelve months ended December 31, 2007 compared to the same period last year primarily due to an increase in allowance for borrowed funds used during construction as a result of the re-application of SFAS No. 71 to our Texas jurisdiction beginning December 31, 2006 and increased construction work in progress and nuclear fuel subject to AFUDC and capitalized interest. This decrease was partially offset by a $1.2 million increase in interest related to our nuclear fuel trust and our pollution control bonds.
Interest charges (credits) decreased $3.8 million in 2006 compared to 2005 due to a $5.1 million decrease in interest on long-term debt and financing obligations resulting from (i) the repurchase and retirement of our first mortgage bonds in May 2005; (ii) the May 2005 issuance of unsecured senior notes at a lower interest rate than the first mortgage bonds; and (iii) the reissuance and remarketing of our pollution control bonds in August 2005 with lower interest rates. This decrease was partially offset by a $0.2 million reduction in allowance for borrowed funds used during construction as a result of completing construction of new Palo Verde Unit 1 steam generators in December 2005.
Income tax expense
Income tax expense, before extraordinary item and the cumulative effect of an accounting change, increased $8.4 million and $7.5 million, respectively, for the twelve months ended December 31, 2007 compared to the same period in 2006 and the twelve months ended December 31, 2006 compared to the same period in 2005, due to increases in pretax income and certain permanent tax differences. The increase in 2007 compared to 2006 was partially offset by adjustments to income tax accruals related to prior years including an adjustment to deferred taxes associated with the accrual of other post-retirement benefits. The increase in income tax expense in 2006 compared to 2005 was partially offset by a reduction in state income taxes resulting from a change in the Texas franchise (income) tax law in 2006 as discussed below.
In May 2006, legislation was approved in Texas revamping the state franchise (income) tax. The tax legislation changes the franchise tax from a tax based upon either taxable capital or taxable income to a 1% tax on taxable margins. The revised franchise tax is effective for tax payments in 2008 based upon 2007 taxable margin. Our taxable margin is based upon revenues taxable for federal income tax purposes less cost of goods sold which includes all costs of producing electricity, but does not include post-production costs. Even with the lower tax rate, the expansion of the tax base resulted in higher franchise tax expense beginning in 2007.
For accounting purposes, the revised franchise tax is an income tax subject to the requirements of SFAS No. 109, Accounting for Income Taxes. SFAS No. 109 requires that deferred tax assets and liabilities be adjusted for changes in tax law in the period of change. As a result, we recorded a $6.2 million
reduction in our net deferred tax liability in the second quarter of 2006 and a corresponding reduction in income tax expense. The adjustment to the net deferred income tax liability included: (i) a reduction of $2.7 million in net Texas deferred income tax liabilities associated with temporary differences that will not reverse in the future under the revised franchise tax calculation; (ii) a reduction of $6.8 million in net Texas deferred income tax liabilities for the change in tax rate from 4.5% to 1% effective in 2007; and (iii) an increase of $3.3 million in deferred federal income tax liabilities to reflect the change in deferred federal income taxes associated with deferred Texas franchise taxes.
The extraordinary gain on re-application of SFAS No. 71 for 2006 relates to our determination that we met the criteria necessary to re-apply SFAS No. 71 to our Texas jurisdiction at December 31, 2006. The re-application of SFAS No. 71 to our Texas jurisdiction resulted in a $6.1 million extraordinary gain, net of tax, at December 31, 2006. For a full discussion on the re-application of SFAS No. 71 to our Texas jurisdiction, see Note A of Notes to Consolidated Financial Statements.
Cumulative effect of accounting change
The cumulative effect of accounting change for 2005 of a $1.1 million charge, net of tax, relates to the adoption of FASB Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations, (FIN 47) in December 2005. FIN 47 provides guidance on the recognition and measurement of liabilities associated with the retirement and disposal obligations of tangible long-lived assets not already accounted for under SFAS No. 143. FIN 47 affected the accounting for the disposal obligations of our fuel oil storage tanks, water wells, evaporative ponds and asbestos at our gas-fired generating stations.
Implementation of SFAS No. 71
Regulated electric utilities typically prepare their financial statements in accordance with SFAS No. 71. Under this accounting standard, certain recoverable costs are shown as either assets or liabilities on a utilitys balance sheet if the regulator provides assurance that these costs will be charged to and collected from the utilitys customers (or has already permitted such cost recovery). The resulting regulatory assets or liabilities are amortized in subsequent periods based upon their respective amortization periods in a utilitys cost of service.
Prior to December 31, 2006 we did not prepare our financial statements in accordance with SFAS No. 71 for our Texas jurisdiction which had been operating under a rate freeze which expired on July 31, 2005. In July 2005, we entered into agreements (Texas Rate Agreements) with El Paso, Texas Commission Staff and other parties in Texas that provide for most retail base rates to remain at their current level through June 30, 2010. During the rate freeze period, if our return on equity falls below the bottom of a defined range, we have the right to initiate a rate case and seek an adjustment to base rates. If our return on equity exceeds the top of the range, we will refund an amount equal to 50% of the pre-tax return in excess of the ceiling. The Texas Rate Agreements required the approval of the Texas Commission to implement the fuel related provisions of the agreements including the sharing of 25% of off-system sales margins with customers through our fixed fuel factor.
On December 8, 2006, the Texas Commission issued a final order approving the fuel related provisions of the Texas Rate Agreements and extending the rate freeze and earnings sharing provisions of the agreements to all customers in Texas based upon settlements with parties to the proceeding. Based
upon the Texas Rate Agreements and order of the Texas Commission extending the agreement to all customers in Texas, we determined that our Texas jurisdiction met the criteria for the re-application of SFAS No. 71 to our Texas jurisdiction as of December 31, 2006.
The re-application of SFAS No. 71 to our Texas jurisdiction recognizes that our rates are based upon our cost of providing service, and the earnings sharing provisions of the rate agreements provide for continued recovery of our costs of providing service during the rate freeze period. In addition, the adoption of a rule by the Texas Commission in October 2004 results in an indefinite delay in retail competition in our Texas service territory and the continued regulation of our retail rates by El Paso and the Texas Commission.
As a result of the re-application of SFAS No. 71 to our Texas jurisdiction at December 31, 2006, we recorded regulatory assets of $9.6 million and recognized an extraordinary gain of $6.1 million, net of tax. Regulatory assets recorded as of December 31, 2006 are currently being recovered through the Texas fixed fuel factor. Other regulatory assets and liabilities will be recorded when recognized in Texas rates. Effective with the re-application of SFAS No. 71 and in accordance with regulatory accounting requirements, we now recognize an allowance for equity and borrowed funds used during construction as a cost of construction of electric plant in service for Texas operations. The allowance for equity funds used during construction is recognized as income and the allowance for borrowed funds used during construction is shown as capitalized interest in our statement of operations. Prior to the re-application of SFAS No. 71, we capitalized interest costs in accordance with SFAS No. 34, Capitalization of Interest Costs.
New accounting standards
In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements. SFAS No. 157 defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles and expands disclosures about fair value measurements. SFAS No. 157 modifies other accounting pronouncements that require or permit fair value measurements and does not require any new fair value measurements. This statement is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. SFAS No. 157 will not have a significant impact on our consolidated financial statements.
In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities Including an Amendment of FASB Statement No. 115. SFAS No. 159 permits entities to choose to measure many financial instruments and certain other items at fair value at specified election dates without having to apply complex hedge accounting provisions. Unrealized gains and losses on items for which the fair value option has been elected should be reported in earnings at each subsequent reporting date. This statement is effective for financial statements issued for fiscal years beginning after November 15, 2007. We have determined that we will continue to recognize the fair value of our financial instruments under current elections and will not change the elections for the fair value measurement of any existing financial instruments under SFAS No. 159.
In December 2007, the FASB issued SFAS No. 141 (revised 2007), Business Combinations which replaces SFAS No. 141, Business Combinations. SFAS No. 141 (revised 2007) applies the acquisition method of accounting to all transactions and other events in which one entity obtains control over one or more businesses and, therefore, improves the comparability of the information about business combinations provided in financial reports. This statement applies prospectively to business
combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008.
In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements an amendment of ARB No. 51. SFAS No. 160 applies to all entities that prepare consolidated financial statements, except not-for-profit organizations, but will affect only those entities that have an outstanding noncontrolling interest in one or more subsidiaries or that deconsolidate a subsidiary. SFAS No. 160 amends Accounting Research Bulletin No. 51 (ARB No. 51) to establish accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. This statement is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008. We currently do not own a non-controlling interest in any subsidiaries the accounting for which would be impacted by SFAS No. 160.
For the last several years, inflation has been relatively low and, therefore, has had little impact on our results of operations and financial condition.
Liquidity and Capital Resources
Our principal liquidity requirements in the near-term are expected to consist of interest payments on our indebtedness, capital expenditures to expand and support electric service obligations, expenditures for nuclear fuel inventory and operating expenses including fuel costs and taxes. Cash flow from operations funded all of our capital requirements except nuclear fuel inventory for the year ended December 31, 2007 and we expect that cash flows from operations will continue to fund a significant portion of capital requirements. As of December 31, 2007, we had approximately $25.0 million in cash and short-term debt securities, a decrease of $15.1 million from the balance of $40.1 million on December 31, 2006.
Capital Requirements. Revenues from the sale of electricity include a recovery of fuel costs, which are essentially recovered from customers through fuel adjustment mechanisms in Texas and New Mexico and a portion through base rates in New Mexico. In Texas, fuel costs are recovered through a fixed fuel factor which may be adjusted twice a year. We record deferred fuel revenues for the under-recovery of fuel costs until they can be recovered from Texas customers. In September 2007, we completed the recovery in Texas of $53.6 million of fuel under-recoveries through a fuel surcharge which began in October 2005 and in January 2007 we completed the recovery in Texas of $34 million of fuel under-recoveries, including interest through the surcharge period, through a fuel surcharge which began in February 2006. The collection of $22.9 million of deferred fuel revenue through surcharges was largely offset by the under-collection of current fuel costs deferred for future recovery from our Texas customers of $22.4 million during 2007. As of December 31, 2007, we had a fuel under-recovery balance of $29.2 million from our Texas customers and an over-recovery balance of $1.5 million from our New Mexico customers. On January 8, 2008, we filed a petition (PUC Docket No. 35204) with the Texas Commission to surcharge $30.1 million of under-recovered fuel costs and interest to our Texas customers. We anticipate beginning to collect this surcharge from our Texas customers in April 2008.
Our long-term liquidity requirements consist primarily of construction of electric utility plant and the payment of interest on debt. Capital requirements for new electric plant were $144.6 million for the year ended December 31, 2007 which were financed with cash flows from operations. Projected utility construction expenditures will consist primarily of expanding and updating the transmission and distribution systems, adding new generation, and making capital improvements and replacements at Palo Verde and other generating facilities. See Part I, Item 1, Business Construction Program. We expect that a significant portion of our construction expenditures will be financed with internal sources of funds through 2008 and the remainder financed with debt.
Our capital requirements for nuclear fuel increased substantially in 2007 as a result of increases in prices for uranium concentrates and increases in our inventory of nuclear fuel feedstock. We finance our nuclear fuel inventory through a trust that borrows under our $200 million credit facility to acquire and process the nuclear fuel. In 2007, borrowings under the credit facility for nuclear fuel increased $36.8 million to $83.0 million as of December 31, 2007 compared to an increase of $4.3 million in 2006 to $46.2 million as of December 31, 2006.
Our cash requirements for federal and state income taxes increased $20.6 million in 2007 as tax loss carryforwards were fully utilized in previous years. Future cash flow requirements for federal income taxes are expected to increase as the Texas fuel under-recovery balance is collected and becomes subject to income tax.
We continually evaluate our funding requirements related to our retirement plans, other postretirement benefit plans, and decommissioning trust funds. We contributed $13.6 million and $13.7 million to our retirement plans during the twelve months ended December 31, 2007 and 2006, respectively. We also contributed $3.4 million to our other postretirement benefit plan for both 2007 and 2006 and $7.0 million and $6.7 million to our decommissioning trust funds during the twelve months ended December 31, 2007 and 2006, respectively.
The Company does not pay dividends on common stock. Since 1999, we have repurchased approximately 19.3 million shares of common stock at an aggregate cost of $269.4 million, including commissions. During 2007, we repurchased 1,344,338 shares of common stock at an aggregate cost of $31.4 million. In November 2007, the Board authorized the repurchase of up to an additional 2 million shares of our outstanding common stock. No shares have been repurchased under the 2007 authorization. We financed capital requirements for common stock repurchases with cash flows from operations. We may make purchases of our stock in the future pursuant to our stock repurchase plan at open market prices and may engage in private transactions, where appropriate. The repurchased shares will be available for issuance under employee benefit and stock incentive plans, or may be retired. Common stock equity as a percentage of capitalization, including the current portion of long-term debt and financing obligations, was 49.7% as of December 31, 2007.
Capital Sources. We maintain the ability to issue long-term debt, if needed, to finance capital requirements and for other corporate purposes including the repurchase of common stock. Our Senior Notes are rated Baa2 by Moodys and BBB by Standard & Poors. Construction expenditures are expected to increase as we plan to add new generation capacity in 2009 and subsequent years. Due to the increased volatility in the natural gas and nuclear fuel markets, we expanded our existing credit facility in July 2007 from $150 million to $200 million and increased the maximum authorized amount of the credit facility which is available for nuclear fuel borrowings from $70 million to $120 million. We expect to initially fund most of our construction expenditures with internally generated funds and, when
appropriate, borrow from our $200 million credit facility or issue long-term debt, consistent with maintaining a capital structure typical of an investment grade regulated electric utility.
Pollution Control Bonds Interest Rates. We currently have approximately $100.6 million of Pollution Control Bonds (the PCBs) for which the interest rate is reset on a weekly dutch auction basis. The PCBs are insured by Financial Guaranty Insurance Company (FGIC). FGICs bond ratings have recently been downgraded by all of the major rating agencies thereby calling into question FGICs claims paying ability in the event of default by the Company. As a result, we have experienced increased yields and resulting interest expense for the PCBs. Although there has not yet been a failed auction of the PCBs, if one were to occur we would be required to pay a default interest rate of 15%. We are currently reviewing our alternatives as it relates to the PCBs and although a definitive decision has not yet been made, we may remarket or refinance the PCBs to fix the interest rates for these bonds for a yet undecided term.
Contractual Obligations. Our contractual obligations as of December 31, 2007 are as follows (in thousands):
Off-Balance Sheet Arrangements
We have no off-balance sheet arrangements that have or are reasonably likely to have a current or future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources.
The following discussion regarding our 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.
We are exposed to market risk due to changes in interest rates, equity prices and commodity prices. Substantially all financial instruments and positions we hold are for purposes other than trading and are described below.
Interest Rate Risk
Our long-term debt obligations are all fixed-rate obligations with varying maturities, except for two of our pollution control bond series which are repriced weekly and our revolving credit facility, which provides for nuclear fuel financing and working capital and which is based on floating rates.
We have issued two series of pollution control bonds in the amounts of $63.5 million and $37.1 million with a variable rate that is repriced weekly until they mature in 2040. These pollution control bonds are carried on the balance sheet at their face value. At December 31, 2007, the variable interest rates were 5.35% and 4.91% for the $63.5 million and the $37.1 million pollution control bond series, respectively. A hypothetical 10% increase in interest rates, annualized from the December 31, 2007 rate, would cause an approximate $0.5 million increase in interest expense. The weekly auction rate market is experiencing higher interest rates and higher rates of failure particularly in issuances such as ours which are backed by monoline insurance carriers. Although a failed auction has not yet been experienced, the default interest rates on the weekly auction rate securities we have outstanding is 15%. We are currently reviewing our alternatives as it relates to the PCBs and although a definitive decision has not yet been made, we may remarket or refinance the PCBs to fix the interest rates for these bonds for a yet undecided term.
To the extent the revolving credit facility is solely utilized for nuclear fuel purchases, interest rate risk, if any, related to the revolving credit facility is substantially mitigated through the operation of the Texas Commission and NMPRC rules which establish energy cost recovery clauses (fuel clauses). Under these rules and fuel clauses, energy costs, including interest expense on nuclear fuel financing, are recovered from our customers.
Our decommissioning trust funds consist of equity securities and fixed income instruments and are carried at market value. We face interest rate risk on the fixed income instruments, which consist primarily of municipal, federal and corporate bonds and which were valued at $54.1 million and $45.6 million as of December 31, 2007 and 2006, respectively. A hypothetical 10% increase in interest rates would reduce the fair values of these funds by $0.7 million and $0.7 million based on their fair values at December 31, 2007 and 2006, respectively.
Equity Price Risk
Our decommissioning trust funds include marketable equity securities of approximately $76.6 million and $69.1 million at December 31, 2007 and 2006, respectively. A hypothetical 20% decrease in equity prices would reduce the fair values of these funds by $15.3 million and $13.8 million based on their fair values at December 31, 2007 and 2006, respectively.
Commodity Price Risk
We utilize contracts of various durations for the purchase of natural gas, uranium concentrates and coal to effectively manage our available fuel portfolio. These agreements contain variable pricing provisions and are settled by physical delivery. The fuel contracts with variable pricing provisions, as well as substantially all of our purchased power requirements, are exposed to fluctuations in prices due to unpredictable factors, including weather and various other worldwide events, which impact supply and demand. However, our exposure to fuel and purchased power price risk is substantially mitigated through the operation of the Texas Commission and NMPRC rules and our fuel clauses, as discussed previously.
In the normal course of business, we enter into contracts of various durations for the forward sales and purchases of electricity to effectively manage our available generating capacity and supply needs. Such contracts include forward contracts for the sale of generating capacity and energy during periods when our available power resources are expected to exceed the requirements of our retail 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 our expected incremental power production costs or to supplement our generating capacity when demand is anticipated to exceed such capacity. As of January 31, 2008, we had entered into forward sales and purchase contracts for energy as discussed in Part I, Item 1, Business Energy Sources Purchased Power and Regulation Power Sales Contracts. These agreements are generally fixed-priced contracts which qualify for the normal purchases and normal sales exception provided in SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, and SFAS No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities, including any effective implementation guidance discussed by the FASB Derivatives Implementation Group and are not recorded at their fair value in our financial statements. Because of the operation of the Texas Commission and NMPRC rules and our fuel clauses, these contracts do not expose us to significant commodity price risk.
Management Report on Internal Control Over Financial Reporting
The Companys management is responsible for establishing and maintaining adequate internal control over financial reporting. Internal control over financial reporting is defined in Rule 13a-15(f) or 15d-15(f) promulgated under the Securities Exchange Act of 1934 as a process designed by, or under the supervision of, the Companys principal executive and principal financial officers and affected by the Companys board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles and includes those policies and procedures that:
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
The Companys management assessed the effectiveness of the Companys internal control over financial reporting as of December 31, 2007. In making this assessment, the Companys management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework.
Based on its assessment, management believes that, as of December 31, 2007, the Companys internal control over financial reporting is effective based on those criteria.
The Companys independent registered public accounting firm, KPMG LLP, has issued an audit report on the Companys internal control over financial reporting. This report appears on page 58 of this report.
INDEX TO FINANCIAL STATEMENTS
Report of Independent Registered Public Accounting Firm
The Board of Directors and Shareholders
El Paso Electric Company:
We have audited the accompanying consolidated balance sheets of El Paso Electric Company and subsidiary as of December 31, 2007 and 2006, and the related consolidated statements of operations, comprehensive operations, changes in common stock equity, and cash flows for each of the years in the three-year period ended December 31, 2007. We also have audited El Paso Electric Companys internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). El Paso Electric Companys management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on these consolidated financial statements and an opinion on the Companys internal control over financial reporting based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the consolidated financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
A companys internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A companys internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the companys assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
As discussed in Notes D, A, K, and H to the consolidated financial statements, the Company changed its accounting for conditional asset retirement obligations in 2005, share-based payments and defined benefit pension and other postretirement plans in 2006, and uncertainty in income taxes in 2007.
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, 2007 and 2006, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2007, in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, El Paso Electric Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
February 28, 2008
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.
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands except for share data)
See accompanying notes to consolidated financial statements.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE OPERATIONS
See accompanying notes to consolidated financial statements.
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCK EQUITY
(In thousands except for share data)
See accompanying notes to consolidated financial statements.
CONSOLIDATED STATEMENTS OF CASH FLOWS