Item 1.
Business
General
El Paso Electric Company is a public utility engaged in the generation, transmission and distribution of electricity in an area of approximately 10,000 square miles in west Texas and southern New Mexico. The Company also serves a wholesale customer in Texas and from time to time 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 1,492 MW. For the year ended December 31, 2006, the Company’s energy sources consisted of approximately 42% nuclear fuel, 25% natural gas, 9% coal, 24% purchased power and less than 1% generated by wind turbines.
The Company serves approximately 350,000 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 57% and 9%, respectively, of the Company’s operating revenues for the year ended December 31, 2006). In addition, the Company’s wholesale sales include sales for resale to other electric utilities and power marketers and from time to time sales to the CFE. 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, oil and copper refining and steel production facilities.
The Company’s principal offices are located at the Stanton Tower, 100 North Stanton, El Paso, Texas 79901 (telephone 915-543-5711). The Company was incorporated in Texas in 1901. As of January 31, 2007, the Company had approximately 1,000 employees, 30% of whom are covered by a collective bargaining agreement. The existing collective bargaining agreement with these employees expired in June 2006, and the Company has been in negotiations on a new collective bargaining agreement since May 2006 with these employees and with the 136 employees from the Company’s meter reading and collections area, facilities services area, and customer service area, who voted for union representation in 2003 and 2004.
The Company makes available free of charge through its website, www.epelectric.com, its annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and all amendments to those reports as soon as reasonably practicable after such material is electronically filed with or furnished to the Securities and Exchange Commission (“SEC”). In addition, copies of the annual report will be made available free of charge upon written request. The SEC also maintains an internet site that contains reports, proxy and information statements and other information for issuers that file electronically with the SEC. The address of that site is www.sec.gov.
Index to Financial Statements Facilities
The Company’s net dependable generating capability of 1,492 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 licensee’s 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 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. In connection with its finding, the NRC stated that it would use the NRC
Index to Financial Statements
action matrix to determine the most appropriate response, including any increase in NRC oversight or identification of actions that APS needs to take in response to this performance deficiency, and will notify APS of its determination at a later date. Under the NRC’s action matrix, this finding, coupled with a previous NRC “yellow” finding (substantial safety significance) relating to a 2004 matter involving Palo Verde’s safety injection systems, will place Palo Verde in the “multiple/repetitive degraded cornerstone” column of the NRC’s action matrix which the Company expects will result in an enhanced NRC inspection regimen. This enhanced inspection regimen and any resulting corrective actions could result in increased operating costs at the plant. Of the 103 commercial nuclear reactors in the United States regulated by the NRC, only three reactors were in the “multiple/repetitive degraded cornerstone” category as of the fourth quarter 2006. The Company is currently unable to predict the impact that the NRC’s increased oversight may have on Palo Verde’s 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. Decommissioning costs are estimated every three years based upon engineering cost studies performed by outside engineers retained by APS.
In accordance with the ANPP Participation Agreement, the Company is required to 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 was above its minimum funding level as of December 31, 2006. The Company will continue to monitor the status of its decommissioning funds and adjust its deposits, if necessary, to remain at or above its minimum accumulation requirements in the future.
In 2005, the Palo Verde Participants approved the 2004 Palo Verde decommissioning study. Some changes in the cost calculations occurred between the prior 2001 study and the 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. The previous cost estimate from the 2001 study estimated that the Company needed to fund approximately $311.6 million (stated in 2001 dollars). Had an equivalent estimate been calculated for the 2001 study in 2004 dollars, based upon the same 3.6% escalation rate utilized in the 2001 study, the previous estimate would have been $346.5 million. See “Spent Fuel Storage” below.
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. The decommissioning study is updated every three years. The 2007 study is expected to be complete in the second quarter of 2008. See “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 decommissioning study assumed that costs to store fuel on-site will
Index to Financial Statements
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 DOE’s 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 DOE’s acceptance of spent fuel. The Company is unable to predict the outcome of these matters at this time.
Disposal of Low-Level Radioactive Waste. Congress has established requirements for the disposal by each state of low-level radioactive waste generated within its borders. Arizona, California, North Dakota and South Dakota have entered into a compact (the “Southwestern Compact”) for the disposal of low-level radioactive waste. California will act as the first host state of the Southwestern Compact, and Arizona will serve as the second host state. The construction and opening of the California low-level radioactive waste disposal site in Ward Valley has been delayed due to extensive public hearings, disputes over environmental issues and review of technical issues related to the proposed site. Palo Verde is projected to undergo decommissioning during the period in which Arizona will act as host for the Southwestern Compact. The opposition, delays, uncertainty and costs experienced in California demonstrate possible roadblocks that may be encountered when Arizona seeks to open its own waste repository. APS currently believes that interim low-level waste storage methods are or will be available to allow each Palo Verde unit to continue to operate and to store safely low-level waste until a permanent disposal facility is available.
Steam Generators. APS identified accelerated degradation in the steam generator tubes of each unit which required the eventual replacement of the steam generators. New steam generators were installed at Unit 2 during 2003 at a cost to the Company of approximately $45.3 million ($36.4 million in direct costs) and in Unit 1 during 2005 at a cost to the Company of approximately $40.1 million ($36.1 million in direct costs). The steam generators at Unit 3 are scheduled to be replaced in late 2007. The steam generator replacements were based on analysis of the net economic benefit from expected improved performance of the respective units and the need to realize continued production from the units over their full licensed lives. The eventual total project cash expenditures for steam generator replacements for Units 1, 2 and 3 are currently estimated to be $710.5 million in direct costs (the Company’s portion being $112.3 million). As of December 31, 2006, the Company has paid approximately $87.7 million of such costs. The Company expects its portion will be substantially funded with internally generated cash. See also Part II, Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Overview.”
Index to Financial Statements After the steam generators were replaced at Palo Verde Unit 1 it operated at significantly reduced power levels from December 25, 2005 until March 18, 2006 and did not operate from March 18, 2006 until early July 2006 while repairs and modifications were made to one of its shutdown cooling lines. Palo Verde Unit 1 reached full capacity on July 16, 2006. Palo Verde Unit 1 experienced a 27 day outage in September and October 2006 to replace pressurizer heaters.
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 Company’s 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 $101 million, subject to an annual limit of $15 million per incident. Based upon the Company’s 15.8% interest in the three Palo Verde units, the Company’s maximum potential assessment per incident for all three units is approximately $47.9 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 $9.5 million for the current policy period.
Newman Power Station
The Company’s Newman Power Station, located in El Paso, Texas, consists of three steam-electric generating units and one combined cycle generating unit with an aggregate capacity of approximately 474 MW. The units operate primarily on natural gas but can also operate on fuel oil.
Rio Grande Power Station
The Company’s Rio Grande Power Station, located in Sunland Park, New Mexico, adjacent to El Paso, Texas, consists of three steam-electric generating units with an aggregate capacity of approximately 229 MW. The units operate primarily on natural gas but can also operate on fuel oil.
Index to Financial Statements Four Corners Station
The Company owns a 7% interest, or approximately 104 MW, in Units 4 and 5 at Four Corners, located in northwestern New Mexico. Each of the two coal-fired generating units has a total generating capacity of 739 MW. The Company shares power entitlements and certain allocated costs of the two units with APS (the Four Corners operating agent) and the other participants, PNM, TEP, SCE and SRP.
Four Corners is located on land 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 Company’s 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 Company’s Hueco Mountain Wind Ranch, located in Hudspeth County, east of El Paso County and adjacent to Horizon City, currently consists of two wind turbines with a total capacity of 1.32 MW 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-Diablo Line. The Company owns a 310-mile, 345 kV transmission line from TEP’s Springerville Generating Plant near Springerville, Arizona, to the Luna Substation near Deming, New Mexico, and to the Diablo Substation near Sunland Park, New Mexico. This transmission line provides an interconnection with TEP for delivery of the Company’s generation entitlements from Palo Verde and, if necessary, Four Corners.
Arroyo-West Mesa Line. The Company owns a 202-mile, 345 kV transmission line from the Arroyo Substation located near Las Cruces, New Mexico, to PNM’s West Mesa Substation located near Albuquerque, New Mexico. This is the primary delivery point for the Company’s generation entitlement from Four Corners, which is transmitted to the West Mesa Substation over approximately 150 miles of transmission lines owned by PNM.
Index to Financial Statements Greenlee-Newman Line. The Company owns 40% of a 60-mile, 345 kV transmission line between TEP’s Greenlee Substation near Duncan, Arizona to the Hidalgo Substation near Lordsburg, New Mexico, approximately 57% of a 50-mile, 345 kV transmission line between the Hidalgo Substation and the Luna Substation and 100% of an 86-mile, 345 kV transmission line between the Luna Substation and the Newman Power Station. These lines provide an interconnection with TEP for delivery of the Company’s entitlements from Palo Verde and, if necessary, Four Corners. The Company owns the Afton 345 kV Substation located approximately 57 miles from the Luna Substation on the Luna-to-Newman portion of the line. The Afton Substation interconnects a generator owned and operated by PNM Resources.
AMRAD-Eddy County Line. The Company owns 66.7% of a 125-mile, 345 kV transmission line from the AMRAD Substation near Oro Grande, New Mexico, to the Company’s and PNM’s (formerly TNP’s) high voltage direct current terminal at the Eddy County Substation near Artesia, New Mexico. The Company owns 66.7% of the terminal. This terminal enables the Company to connect its transmission system to that of SPS (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.
Environmental Matters
The Company is subject to regulation with respect to air, soil and water quality, solid waste disposal and other environmental matters by federal, state, tribal and local authorities. Those authorities govern current facility operations and have continuing jurisdiction over facility modifications. Failure to comply with these environmental regulatory requirements can result in actions by regulatory agencies or other authorities that might seek to impose on the Company administrative, civil, and/or criminal penalties. If the United States regulates green house gas emissions, the Company’s fossil fuel generation assets will be faced with the additional cost of monitoring, controlling and reporting these emissions. A significant portion of the Company’s generation assets are nuclear and gas fired. As a result, the Company does not believe such regulations would impose greater burdens on the Company than on most other electric utilities. 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. Environmental regulations can change rapidly and are often difficult to predict. While the Company strives to prepare for and implement changes necessary to comply with changing environmental regulations, substantial expenditures may be required for the Company to comply with such regulations in the future.
The Company analyzes the costs of its obligations arising from environmental matters on an ongoing basis and believes it has made adequate provision in its financial statements to meet such obligations. As a result of this analysis, the Company has a provision for environmental remediation
Index to Financial Statements
obligations of approximately $2.0 million as of December 31, 2006, which is related to compliance with federal and state environmental standards. However, unforeseen expenses associated with compliance could have a material adverse effect on the future operations and financial condition of the Company.
Along with many other companies, the Company received from the Texas Commission on Environmental Quality (“TCEQ”) a request for information 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 Company’s position is that any liability it may have related to the SESCO site was discharged in the Company’s bankruptcy. At this time, the Company has not agreed to the 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.
In the first quarter of 2006, a fuel oil release was discovered at one of the Company’s local generating plants. The fuel oil from an above ground storage tank spilled due to a pipeline malfunction and was contained inside a safety corridor. It is estimated that approximately 95% of fuel oil released was recovered and placed back into the fuel inventory. During the second quarter of 2006, the Company completed its assessment of the situation and started the remediation process on the contaminated soil containing the remaining 5% of the fuel oil. The estimated cost to address this incident is $0.8 million which has been recorded as maintenance expense in the Company’s financial statements.
On September 26, 2006, the Secretary of the New Mexico Environment Department issued a Compliance Order concerning the Company’s 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 no penalties have been incurred.
Except as described herein, the Company is not aware of any other active investigation of its compliance with environmental requirements by the Environmental Protection Agency, the TCEQ or the New Mexico Environment Department which is expected to result in any material liability. Furthermore, except as described herein, the Company is not aware of any unresolved, potentially material liability it would face pursuant to the Comprehensive Environmental Response, Comprehensive Liability Act of 1980, also known as the Superfund law.
Construction Program
Utility construction expenditures reflected in the following table consist primarily of local generation, 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
Index to Financial Statements
Palo Verde, including the fabrication and installation of Palo Verde Unit 3 steam generators and reactor head vessel replacements for all three units at Palo Verde. Replacement power costs expected to be incurred during the replacement of Palo Verde Unit 3 steam generators and the replacement reactor vessel heads at Palo Verde are not included in construction costs. Studies indicate that the Company will need additional power generation resources to meet increasing load requirements on its system which are included in the table below.
The Company’s estimated cash construction costs for 2007 through 2010 are approximately $716 million. Actual costs may vary from the construction program estimates shown. Such estimates are reviewed and updated periodically to reflect changed conditions.
(1) Does not include acquisition costs for nuclear fuel. See “Energy Sources - Nuclear Fuel.”
(2) Includes $226 million for local generation, $17 million for the Four Corners Station and $119 million for the Palo Verde Station.
(3) Includes expenditures to meet needs of Ft. Bliss expansion to support increase of 20,000 soldiers resulting from Base Reallignment and Closure Commission recommendations.
Energy Sources
General
The following table summarizes the percentage contribution of nuclear fuel, natural gas, coal and purchased power to the total kWh energy mix of the Company. Energy generated by wind turbines accounted for less than 1% of the total kWh energy mix.
Nuclear generation was below historical levels during 2006 as a result of an extended unplanned outage at Palo Verde Unit 1 and refueling outages at Palo Verde Units 2 and 3 during 2006. At December 31, 2006, Palo Verde was operating at full capacity. Allocated fuel and purchased power costs are generally passed through directly to customers in Texas and New Mexico pursuant to applicable regulations. Historical fuel costs and revenues are reconciled periodically in proceedings
Index to Financial Statements
before the Texas Commission and the NMPRC. See “Regulation - Texas Regulatory Matters” and “- New Mexico Regulatory Matters.”
Nuclear Fuel
The nuclear fuel cycle for Palo Verde consists of the following stages: the mining and milling of uranium ore to produce uranium concentrates; the conversion of the uranium concentrates to uranium hexafluoride (“conversion services”); the enrichment of uranium hexafluoride (“enrichment services”); the fabrication of fuel assemblies (“fabrication services”); the utilization of the fuel assemblies in the reactors; and the storage and disposal of the spent fuel. The Palo Verde Participants have contracts in place that will furnish 100% of Palo Verde’s operational requirements for uranium concentrates, conversion services and enrichment services through 2008. Such contracts could also provide 100% of enrichment services in 2009 and 2010. The Palo Verde Participants have a contract 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 Company has available a total of $150 million under a revolving credit facility that provides for both working capital and up to $70 million for the financing of nuclear fuel. During the term of the agreement, the revolving credit facility may be increased to $200 million. This facility was renewed in 2006 for a five-year term ending April 11, 2011. At December 31, 2006, approximately $46.2 million had been drawn to finance nuclear fuel. The Company anticipates that its borrowings to finance nuclear fuel will likely increase in the future due to expected increased costs for uranium concentrates. This financing is accomplished through a trust that borrows under the credit facility to acquire and process the nuclear fuel. The Company is obligated to repay the trust’s borrowings with interest. In the Company’s financial statements, the assets and liabilities of the trust are consolidated and reported as assets and liabilities of the Company.
Natural Gas
The Company manages its natural gas requirements through a combination of a long-term supply contract and spot market purchases. The long-term supply contract provides for firm deliveries of gas at market-based index prices. In 2006, the Company’s natural gas requirements at the Newman and Rio Grande Power Station were met with both short-term and long-term natural gas purchases from various suppliers and it is expected to continue in 2007. 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 Station.
Natural gas for the Newman and Copper Power Stations is also supplied pursuant to an intrastate natural gas contract that expires in 2007. The Company is currently in the process of replacing this contract.
Index to Financial Statements Coal
APS, as operating agent for Four Corners, purchases Four Corners’ coal requirements from a supplier with a long-term lease of coal reserves owned by the Navajo Nation. The 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 plant’s operational requirements for its useful life.
Purchased Power
To supplement its own generation and operating reserves, the Company engages in firm and non-firm power purchase arrangements which may vary in duration and amount based on evaluation of the Company’s resource needs and the economics of the transactions. 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.
In October 2006, the Company received notice from SPS alleging that SPS has been subject to adverse regulatory action by the Texas Commission in a fuel surcharge proceeding (Docket No. 32685) which purportedly determined that SPS should assign incremental fuel costs to the contract. The contract provides for SPS to charge average fuel costs. The Company does not believe that the Texas Commission’s order in Docket No. 32685 constitutes an adverse regulatory action under the contract and intends to vigorously defend its position. The Company is unable to predict the outcome of this matter. If the Company is unsuccessful in defending its position or negotiating mutually satisfactory modifications to the contract, SPS may be able to terminate the contract early. If the contract is terminated early, the Company would need to replace the power available to it under the SPS contract.
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 2006 primarily to replace the Company’s generation resources during planned and unplanned outages and for economic reasons.
Index to Financial Statements Operating Statistics
(1) Includes spot firm sales and net losses of 260,000 kW, 252,000 kW and 243,000 kW for 2006, 2005 and 2004, respectively.
(2) Excludes 133,000 kW for 2006 and 103,000 kW for 2005 and 2004 of firm on and off-peak purchases.
(3) System capacity factor includes average firm system purchases of 133,000 kW for 2006 and 103,000 kW for 2005 and 2004.
Index to Financial Statements Regulation
General
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 Company’s wholesale transactions. The decisions of the Texas Commission, NMPRC and the FERC are subject to judicial review.
Texas Regulatory Matters
Texas Freeze Period and Franchise Agreement. On July 21, 2005, the Company entered into an agreement with the City to extend its existing freeze period for an additional five years expiring June 30, 2010. Under the City Rate Agreement which became effective as of July 1, 2005, most retail base rates will remain at their current level through June 30, 2010. If, during the term of the agreement, the Company’s 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 Company’s return on equity exceeds the top of the range, the Company will refund, at the City’s direction, an amount equal to 50% of the pre-tax return in excess of the ceiling. The range is market-based, and at current rates, would be a range of approximately 8.3% to 12.3%.
Pursuant to the City Rate Agreement, the Company will share with its Texas customers 25% of off-system sales margins and wheeling revenues. 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”). On December 8, 2006, the Texas Commission approved the margin sharing provisions of the City Rate Agreement in PUC Docket No. 32289 pursuant to settlement agreements in that docket.
In PUC Docket No. 32289, the Company entered into settlement agreements with the Texas Commission Staff, a large industrial customer, the City, 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 Company’s support of low-income energy efficiency programs; and (iv) provides that after the expiration of the City Rate Agreement, 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 the end of the City Rate Agreement on 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 City Rate Agreement, 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, the City, 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.
Index to Financial Statements Under the terms of the City Rate Agreement, the Company has committed to spend at least 0.3% of its El Paso revenues on civic and charitable causes within the City. The Company and the City also engaged, at the Company’s expense, the services of an independent consultant to review the reasonableness of certain operating expenses of the Company. In June 2006, the consultant issued its report stating that such expenses were reasonable and, as a result, the City Rate Agreement remained in full force and effect. The City Rate Agreement may also be reopened by the City in the event of a company merger to seek rate reductions based on post-merger synergy savings.
The City also granted to the Company a new 25-year franchise which became effective August 2, 2005 and increased franchise fee payments from 2% to 3.25% of gross receipts earned within the City limits. The franchise governs the Company’s usage of City-owned property and the payment of franchise fees. In August 2005, a dispute rose over the timing and characterization of past and future franchise fee payments to the City. The Company has continued to make payments in accordance with the terms of the agreement while parties discuss a resolution of this issue. The Company does not believe that such resolution will have a material adverse impact on its results of operations or financial condition.
Fuel and Purchased Power Costs. Although the Company’s base rates are frozen under the City Rate Agreement, pursuant to Texas Commission rules and the City Rate Agreement, the Company’s fuel costs including purchased power energy costs are passed through to 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. Pursuant to Texas Commission rules, the Company must file a fuel reconciliation for the three-year period ending February 28, 2007 by August 31, 2007.
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 as a result of higher natural gas prices. 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 Commission’s decision in PUC Docket No. 32289, the margin sharing proceeding 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 30, 2007. The settlement requests 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% 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. The new fuel factors were approved on an interim basis and placed into effect in customer bills in February 2007. The settlement is subject to final approval by the Texas Commission which is expected in March 2007.
Index to Financial Statements Palo Verde Performance Standards. The Texas Commission established performance standards for the operation of Palo Verde pursuant to which each Palo Verde unit is evaluated annually to determine whether its three-year rolling average capacity factor entitles the Company to a reward or subjects it to a penalty. The capacity factor is calculated as the ratio of actual generation to maximum possible generation. If the capacity factor, as measured on a station-wide basis for any consecutive 24-month period, should fall below 35%, the parties to the City Rate Agreement can seek different rate treatment for Palo Verde. The removal of Palo Verde from rate base could have a significant negative impact on the Company’s revenues and financial condition. The Company has calculated the performance rewards for the reporting periods ending in 2006 and 2004 to be approximately $0.4 million and $0.2 million, respectively. The 2006 and 2004 rewards will be included along with energy costs incurred and fuel revenue billed as part of the Texas Commission’s review during a future periodic 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 Company’s books until the Texas Commission has ordered a final determination in a fuel proceeding or comparable evidence of collectibility is obtained. Performance penalties are recorded when assessed as probable by the Company.
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 Commission order adopting this agreement, the Company made a payment in November 2004 in the amount of $5.8 million to El Paso County General Assistance Agency and Big Bend Community Center Committee, Inc. In further compliance with the Texas Commission’s order, the Company sought and received approval by the El Paso City Council in January 2006 to remit to the City approximately $5.8 million in Palo Verde performance reward funds to fund demand side management programs as requested such as weatherization with a focus on programs to assist small business and commercial customers. As of December 31, 2006 $6.0 million, including accrued interest, remains to be paid under these agreements and is recorded as a liability on the Company’s 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. The Texas Restructuring Law, however, specifically recognized and preserved the Company’s Texas Rate Stipulation and Texas Settlement Agreement by, among other things, exempting the Company’s Texas service area from retail competition until the end of the Freeze Period. On October 13, 2004, the Texas Commission approved a rule further delaying retail competition in the Company’s Texas service territory. The rule approved by the Texas Commission sets a schedule which identifies various milestones for the Company to reach before competition can begin. The first milestone calls for the development, approval by the FERC, and commencement of independent operation of an RTO in the area that includes the Company’s 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 Commission’s final evaluation of the market’s readiness to offer fair competition and reliable service to all retail customers. The Company believes that adoption of this rule will likely delay retail competition in El Paso for a number of years. There is substantial uncertainty about both the regulatory framework and market conditions that will exist if and when retail competition
Index to Financial Statements
is implemented in the Company’s service territory, and the Company may incur substantial preparatory, restructuring and other costs that may not ultimately be recoverable. There can be no assurance that deregulation would not adversely affect the future operations, cash flows and financial condition of the Company.
Renewables and Energy Efficiency Programs. Notwithstanding the Texas Commission’s approval of a rule further delaying competition in the Company’s 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 will have to annually obtain its pro rata share of renewable energy credits as determined by the Program Administrator (the Electric Reliability Council of Texas). The Company’s ultimate obligation to obtain renewable energy credits will not be known until January 31 of the year following the compliance year, and it will have until March 31 to obtain, if necessary, and submit to the Program Administrator, sufficient credits. The Company obtained the required renewable energy credits to meet its expected obligations through 2006. In addition, beginning in 2006, the Company was required to fund incentives for energy efficiency savings that will achieve the goal of meeting 5% of its Texas jurisdiction growth in demand through energy efficiency savings. The goal is increased to 10% of the Company’s Texas jurisdiction growth in demand annually beginning January 1, 2008. For the plan year ended December 31, 2006, the Company incurred expenditures for incentives of approximately $0.6 million. Pursuant to the Company’s Energy Efficiency Plan filed with the Texas Commission, the Company expects to spend approximately $6.1 million in costs through 2009 for incentive payments to achieve its energy efficiency goal.
New Mexico Regulatory Matters
NMPRC Case No. 06-00258-UT 2006 Rate Filing. On June 30, 2006, the Company filed a petition with the NMPRC to increase overall rates by approximately $31.7 million. The current rate case filing requests an increase in non-fuel base rates of $13.1 million and an increase of $18.6 million in fuel and purchased power cost recovery. The Company requested that all fuel and purchased power costs be recovered through its Fuel and Purchased Power Cost Recovery Clause (“FPPCAC”). The Company’s requested FPPCAC was based on natural gas costs of $9.50 per MMBtu for the forecast period June 2007 through May 2008. In addition, the Company requested that power provided from Palo Verde Unit 3, which is a deregulated non-utility plant in New Mexico, be priced at the lowest market price for equivalent firm capacity and energy available to the Company. Requested rates would not be effective before July 1, 2007. The NMPRC Staff, the New Mexico Attorney General and the Department of Defense submitted responsive testimony on November 29, 2006 and the Company submitted rebuttal testimony on January 10, 2007. A stipulation (“2007 New Mexico Stipulation”) was filed on February 6, 2007 resolving all issues in the case subject to NMPRC approval. The 2007 New Mexico Stipulation is unopposed and signed by all parties in the proceeding, except the New Mexico Industrial Energy Consumers (“NMIEC”) and PNM.
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. The 2007 New Mexico Stipulation reflects revised fuel costs for the June 2007 through May 2008 forecast period which reflect average natural gas costs of $7.20 per MMBtu. Most of the Company’s fuel and purchased power costs during the period of the 2007 New Mexico Stipulation will be recovered through base rates with any difference between actual fuel and purchased power costs and the amount included in base rates will be recovered or refunded through
Index to Financial Statements
the FPPCAC. Rates will continue in effect until changed by the NMPRC after the Company’s 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 July 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 included in base rates and the FPPCAC based upon the cost of capacity and fuel charges 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 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 the New Mexico jurisdictional portion of 90% 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 if the SPS purchased power contract is modified or terminated. 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.
A hearing on the 2007 New Mexico Stipulation will be held on March 20, 2007. A final order of the NMPRC is expected no later than July 19, 2007. Management cannot predict whether the NMPRC will approve the 2007 New Mexico Stipulation.
Fuel and Purchased Power Costs. In April 2004, the NMPRC, as part of the 2004 New Mexico Stipulation and Final Order in NMPRC Case No. 03-00302, approved a FPPCAC. The Company currently recovers fuel and purchased power costs in base rates in the amount of $0.01949 per kWh and recovers the remaining fuel and purchased power costs through its FPPCAC. Fuel and purchased power costs associated with 10 percent of the Company’s jurisdictional retail sales in New Mexico are fixed at $0.021 per kWh, and are not reconcilable. See discussion of NMPRC Case No. 06-00258-UT above.
On August 29, 2005, the Company filed the annual reconciliation of its FPPCAC for the period June 1, 2004 through May 31, 2005 in compliance with the requirements of the NMPRC’s Final Order in NMPRC Case No. 03-00302-UT. The Company requested reconciliation of its fuel and purchased power costs for this period, except for the 10 percent portion, and requested recovery of $1.3 million for the New Mexico jurisdictional portion of purchased power capacity costs. The NMPRC Final Order issued April 11, 2006 reconciled the Company’s FPPCAC for the limited purpose of summarizing and verifying all actual revenues and costs, but did not establish the reasonableness of the Company’s fuel and purchased power costs for the reconciliation period. On August 30, 2006, the Company filed the annual reconciliation for its FPPCAC for the period June 1, 2005 through May 31, 2006. As discussed above, the 2007 New Mexico Stipulation provides for final reconciliation of fuel and purchased power costs through December 31, 2005. The Company believes it has fully supported the recovery of all of its applicable fuel and purchased power costs for the period, but cannot predict how the NMPRC will rule on the 2007 New Mexico Stipulation or in a future rate case addressing fuel and purchased power costs
Index to Financial Statements
after December 31, 2005. An adverse ruling by the NMPRC could have a material negative effect on the Company’s results of operations.
Renewables. The New Mexico Renewable Energy Act of 2004 requires that, by January 1, 2006, renewable energy comprise no less than 5% of the Company’s total retail sales to New Mexico customers. The requirement increases by 1% annually until January 1, 2011, when the renewable portfolio standard shall reach a level of 10% of the Company’s total retail sales to New Mexico customers and will remain fixed at such level thereafter. The Company has met all requirements to date. On September 1, 2006, the Company filed its annual Procurement Plan detailing its proposed actions to comply with the Renewable Energy Act through 2011.
The NMPRC approved the Company’s 2006 Annual Procurement Plan in December 2006, acknowledging the Company’s existing plan to (i) enter into a contract to purchase renewable energy certificates (“RECs”) for full requirements in 2006 and 2007 and approximately 50% of the Company’s requirements in 2008 through 2011 and (ii) to create a deferral, with carrying costs for future recovery from customers of up to $0.2 million in costs related to the issuance of a diversity RFP for renewable resources and for investigation of small projects to meet the remaining requirements in the 2008 to 2011 timeframe and thereafter. In addition, the Commission authorized the Company to enter into two 20-year purchased power agreements to purchase energy from an 8 megawatt low-emissions biomass generating facility and from a 6 kilowatt solar energy generating facility. Both generating facilities will be located within the Company’s New Mexico service area. Costs incurred by the Company to purchase RECs to meet the requirements of the New Mexico Renewable Energy Act are to be recovered through the FPPCAC as purchased power costs from New Mexico customers pursuant to the Renewable Energy Act and the NMPRC Final Order in NMPRC Case No. 05-00231-UT. The NMPRC’s decision in that case has been appealed to the New Mexico Supreme Court by the New Mexico Industrial Energy Consumers, and oral argument is scheduled for March 12, 2007. The Company is unable to predict how the New Mexico Supreme Court will rule in this proceeding.
Federal Regulatory Matters
Transmission Dispute with Tucson Electric Power. 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 claimed that, under the Transmission Agreement, it was entitled to up to 400 MW of transmission rights on the Company’s 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 Arizona. The Company asserted that TEP’s 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 Company’s 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. TEP’s request for a rehearing of the FERC’s 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; however, the hearing was held in abeyance to allow time for the parties to attempt to negotiate a settlement. The Company and TEP have been unable to reach a settlement, and a hearing before an administrative law judge on the dispute has been scheduled to begin
Index to Financial Statements
on May 22, 2007. An initial decision of the administrative law judge is expected no later than January 30, 2008. While the Company believes that it is not probable that TEP will prevail, the Company cannot predict the outcome of this case. During 2006 TEP paid the Company $3.5 million for transmission service relating to the LEF of which the Company has included $3.1 million in its 2006 operating revenues. If the FERC were to rule in TEP’s favor, the Company may be required to refund all of the $3.5 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 Company’s results of operations.
RTOs. FERC’s rule (“Order 2000”) on RTOs strongly encourages, but does not require, public utilities to form and join RTOs. The Company is an active participant in the development of WestConnect, formerly known as the Desert Southwest Transmission and Reliability Operator. A WestConnect Memorandum of Understanding (“MOU”) was signed by the Company and nine other transmission owners on December 6, 2004. On November 21, 2005 an eleventh member joined. This MOU 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 Company’s exports of power to the CFE in Mexico pursuant to a license granted by the DOE and a presidential permit. The DOE has determined that all such exports over international transmission lines shall be made in accordance with Order No. 888, which established the FERC rules for open access.
The DOE is authorized to assess operators of nuclear generating facilities a share of the costs of decommissioning the DOE’s uranium enrichment facilities and for the ultimate costs of disposal of spent nuclear fuel. See “Facilities - Palo Verde Station - Spent Fuel Storage” for discussion of spent fuel storage and disposal costs.
Nuclear Regulatory Commission. The NRC has jurisdiction over the Company’s licenses for Palo Verde and regulates the operation of nuclear generating stations to protect the health and safety of the public from radiation hazards. The NRC also has the authority to grant license extensions pursuant to the Atomic Energy Act of 1954, as amended.
Index to Financial Statements Sales for Resale
The Company provides up to 10 MW of firm capacity, associated energy, and transmission service to the Rio Grande Electric Cooperative pursuant to an ongoing contract which requires a two-year notice to terminate. 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 2007. The Company has also entered into other longer-term sales for which the supply is fully hedged.
Franchises and Significant Customers
City of El Paso Franchise
The Company has a franchise agreement with the City of El Paso, the largest city it serves, through July 31, 2030. The franchise agreement includes a 3.25% annual franchise fee and allows the Company to utilize public rights-of-way necessary to serve its retail customers within the City.
Las Cruces Franchise
In February 2000, the Company and Las Cruces entered into a seven-year franchise agreement with a 2% annual franchise fee (approximately $1.4 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 by waiving its option to purchase the Company’s distribution system pursuant to the terms of a February 2000 settlement agreement.
Military Installations
The Company currently serves Holloman Air Force Base (“Holloman”), White Sands Missile Range (“White Sands”) and the United States Army Air Defense Center at Fort Bliss (“Ft. Bliss”). The Company’s sales to the military bases represent approximately 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 new contract, subject to regulatory approval, 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.
Index to Financial Statements
Item 1A.
Item 1A.
Risk Factors
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, the performance of our customers and the decisions of regulatory agencies. Our common stock price and creditworthiness will be affected by national and international macroeconomic trends, general market conditions and the expectations of the investment community, all of which are largely beyond our control. In addition, the following statements highlight risk factors that may affect our consolidated financial condition and results of operations. These are not intended to be an exhaustive discussion of all such risks, and the statements below must be read together with factors discussed elsewhere in this document and in our other filings with the SEC.
Our Costs Could Increase 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 622 MW of generating capacity. Palo Verde represents approximately 40% of our available net generating capacity and represented approximately 42% of our available energy for the twelve months ended December 31, 2006. Palo Verde comprises 43% 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. The NRC recently placed Palo Verde in the “multiple/repetitive degraded cornerstone” column of its action matrix which we expect will result in an enhanced NRC oversight and 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) the replacement of steam generators in Palo Verde Unit 3; (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. At the same time, our retail base rates in Texas are effectively capped through June 2010. As a result, 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, if the 2007 New Mexico Stipulation is approved by the NMPRC. 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 Pass Through All of Our Fuel Expenses to Customers
In general, by law, we are entitled to pass through our prudently incurred fuel and purchased power expenses to our customers in Texas and New Mexico. We agreed as part of the 2004 New Mexico Stipulation to a fixed price for fuel and purchased power expenses for 10 percent of the kilowatt-hours for retail sales in New Mexico pursuant to a base rate agreement that expires in 2007.
Index to Financial Statements
This agreement also allows us to price a portion of power from Palo Verde Unit 3 at prices which partially track gas prices. To the extent that this indirect “hedge” does not perfectly track our costs, we are subject to the risk of increased costs of fuel and purchased power costs that would not be recoverable. The portion of fuel expense that is not fixed in New Mexico and all of Texas fuel expense 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 except for the portion fixed in New Mexico and the repriced fuel costs for Palo Verde Unit 3. 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 2004 and 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, 2006 and December 31, 2005, the Company had deferred fuel balances of $32.6 million and $92.3 million, respectively. A surcharge to collect fuel under-recoveries of $53 million over a 24-month period was placed into effect in Texas in October 2005. A second surcharge was placed into effect on an interim basis in Texas in February 2006 to collect $34 million over a twelve-month period. 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 Verde’s 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.
Index to Financial Statements Potential for Strike or Lock Out Due to Union Employees
Working Without a Contract
We have historically had a union workforce of approximately 300 employees. In 2003 and 2004, 136 additional employees, from the meter reading, collections, facilities services, and customer service areas, voted to join the union. The union contract for the historical group of 300 union employees expired on June 30, 2006, and currently all 436 union employees are working without a contract. We have been engaged in negotiations with the union trying to achieve a contract for all the union employees. While we will continue our effort to reach agreement on the terms of a new contract with all union employees, these employees could strike or we could lock them out. If a strike or lock out occurs, we will implement a work continuation plan. However, we may experience a reduction in the reliability of our service and may incur added expense to hire replacement workers, train and equip non-union employees, and provide security for our facilities.
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. On October 13, 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.
Item 1B.
Item 1B.
Unresolved Staff Comments
None.
Index to Financial Statements Executive Officers of the Registrant
The executive officers of the Company as of February 8, 2007, were as follows:
Name
Age
Current Position and Business Experience
Gary R. Hedrick
Chief Executive Officer, President and Director since November 2001.
J. Frank Bates
Executive Vice President and Chief Operating Officer since May 2005; Executive Vice President and Chief Operations Officer from November 2001 to May 2005.
Scott D. Wilson
Executive Vice President, Chief Financial and Chief Administrative Officer since February 2006; Senior Vice President, Chief Financial Officer from May 2005 to February 2006; Vice President - Corporate Planning and Controller from February 2005 to May 2005; Controller from September 2003 to February 2005; Owner of Wilson Consulting Group from June 1992 to September 2003.
Steven P. Busser
Vice President - Treasurer and Chief Risk Officer since May 2006; Vice President - Regulatory Affairs and Treasurer from February 2005 to April 2006; Treasurer from February 2003 to February 2005; Assistant Chief Financial Officer from June 2002 to February 2003; Vice President - International Controller for Affiliated Computer Services, Inc. from August 2001 to June 2002.
David G. Carpenter
Vice President - Corporate Planning and Controller since August 2005; Director - Texas Regulatory Services for American Electric Power Services Corporation from June 2000 to August 2005.
Robert C. Doyle
Vice President - New Mexico Affairs since February 2007; Director - New Mexico Affairs from January 2007 to February 2007; Manager - Corporate Projects Office from August 2004 to January 2007; Project Manager - Corporate Transition to Competition from January 2004 to August 2004; Supervisor - Distribution Dispatch from August 1999 to October 2003.
Fernando J. Gireud
Vice President - Safety, Environmental, Power Marketing and International Affairs since February 2006; Vice President - Power Marketing and International Business from February 2003 to February 2006; Vice President - International Business from July 2002 to February 2003; Director - International Business Affairs from February 2002 to July 2002; Director - International Business Affairs - MiraSol from November 1999 to February 2002.
Hector Gutierrez, Jr.
Executive Vice President - External Affairs since June 2006; Managing Director - Governmental Operations, Hillco Partners from October 2002 to July 2006; Public Affairs Consultant - City of El Paso and the El Paso Water Utilities from January 1995 to September 2002.
Helen Knopp
Vice President - Public Affairs since May 2006; Vice President - Customer and Public Affairs from April 1999 to April 2006.
Kerry B. Lore
Vice President - Administration since May 2003; Controller from October 2000 to May 2003.
Hector R. Puente
Vice President - Transmission and Distribution since May 2006; Vice President - Distribution from February 2006 to April 2006; Vice President - Power Generation from April 2001 to February 2006.
Andres Ramirez
Vice President - Power Generation since February 2006; Vice President - Safety, Environmental and Resource Planning from July 2005 to February 2006; Executive Director - Operations for Sempra Energy Texas Service from August 2004 to July 2005; Senior Vice President - Power Production for Austin Energy from 2001 to 2004.
Gary Sanders
General Counsel since February 2006; Assistant General Counsel and Assistant Secretary from July 2004 to February 2006; Assistant General Counsel from January 2003 to July 2004; Shareholder in law firm of Gordon & Mott PC from April 1994 to December 2002.
Guillermo Silva, Jr.
Corporate Secretary since February 2006; Vice President - Information Services from February 2003 to February 2006; Corporate Secretary from January 1994 to February 2003.
John A. Whitacre
Vice President - System Operations and Planning since May 2006; Vice President - Transmission from February 2006 to April 2006; Vice President - Transmission and Distribution from July 2002 to February 2006; Assistant Vice President - System Operations from August 1989 to July 2002.
The executive officers of the Company are elected annually and serve at the discretion of the Board of Directors.
Index to Financial Statements
Item 2.
Item 2.
Properties
The principal properties of the Company are described in Item 1, “Business,” and such descriptions are incorporated herein by reference. Transmission lines are located either on private rights-of-way, easements, or on streets or highways by public consent.
In addition, the Company leases executive and administrative offices in El Paso, Texas under a lease which expires in May 2007. The Company is currently in negotiations regarding this lease. In addition, the Company leases certain warehouse facilities in El Paso, Texas under a lease which expires in January 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 seven years.
Item 3.
Item 3.
Legal Proceedings
The Company is a party to various legal actions. In many of these matters, the Company has excess casualty liability insurance that covers the various claims, actions and complaints. Based upon a review of these claims and applicable insurance coverage, 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 May 21, 2003, the Company was served with a complaint by the Port of Seattle seeking civil damages under the Sherman Act, the Racketeer Influenced and Corrupt Organization Act, and state antitrust laws, as well as for fraud (Port of Seattle v. Avista Corporation, et al., No. CV03-117OP). The complaint was filed in the United States District Court for the Western District of Washington. The complaint alleges that the Company, indirectly through its dealings with Enron, conspired with the other named defendants to manipulate the California energy market, which had the effect of artificially inflating the price that the Port of Seattle paid for electricity. The Company, together with several other defendants, filed a motion to dismiss. On May 12, 2004, the Court granted the Company’s motion, and the suit was dismissed. The Port of Seattle has filed an appeal of the Court’s decision with the U. S. Court of Appeals for the Ninth Circuit. On March 30, 2006, the Court of Appeals upheld the dismissal of this matter. No further appeal was filed and the dismissal is final.
On May 5, 2004, Wah Chang, a specialty metals manufacturer which operates a plant in Oregon, filed suit against the Company and other defendants in the United States District Court for the District of Oregon. (Wah Chang v. Avista Corporation, et al., No. 04-619AS). The complaint makes substantially the same allegations as were made in Port of Seattle and seeks the same types of damages. In addition, on June 7, 2004, the City of Tacoma filed suit against the Company and other defendants in the United States District Court for the Western District of Washington (City of Tacoma v. American Electric Power Service Corp., et al., C04-5325RBL). This complaint also makes substantially the same allegations as were made in Port of Seattle and seeks civil damages (including treble damages) from the Company and the other defendants for violations of certain antitrust provisions under the Sherman Act. Both of these matters were transferred to the same court that heard and dismissed the Port of Seattle lawsuit and on February 11, 2005, the Court granted the Company’s motion to dismiss both cases. Wah Chang and the City of Tacoma have both filed notices of appeal with the U.S. Court of Appeals for the Ninth Circuit. The parties have filed briefs in both cases and oral arguments are scheduled for
Index to Financial Statements
April 10, 2007. While the Company believes that these matters are without merit and intends to defend itself vigorously, 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.
Item 4.
Item 4.
Submission of Matters to a Vote of Security Holders
No matter was submitted to vote of the Company’s security holders through the solicitation of proxies or otherwise during the fourth quarter of 2006.
Index to Financial Statements
PART II
Item 5.
Item 5.
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Repurchases of Equity Securities
The Company’s common stock trades on the New York Stock Exchange under the symbol “EE.” The high, low and close sales prices for the Company’s common stock, as reported in the consolidated reporting system of the New York Stock Exchange for the periods indicated below were as follows:
Index to Financial Statements Performance Graph
The following graph compares the performance of the Company’s Common Stock to the performance of the NYSE Composite, and the Edison Electric Institute’s Index of investor-owned electric utilities setting the value of each at December 31, 2001 to a base of 100. The table sets forth the relative yearly percentage change in the Company’s cumulative total shareholder return as compared to the NYSE, and the EEI, as reflected in the graph.
As of January 31, 2007, there were 4,132 holders of record of the Company’s common stock. The Company does not anticipate paying dividends on its common stock in the near-term. The Company intends to continue its stock repurchase programs with the goal of maintaining or improving its capital structure, bond ratings, and earnings per share.
Since the inception of the stock repurchase programs in 1999, the Company has repurchased a total of approximately 18.0 million shares of its common stock at an aggregate cost of $238 million, including commissions. In September 2006, the Board of Directors (the “Board”) authorized the repurchase of up to 2.3 million shares of the Company’s outstanding common stock (the “2006 Plan”). The shares authorized under the 2006 Plan are in addition to the shares which were available under a buy back program previously approved by the Board in February 2004 (the “2004 Plan”). During 2006, the Company repurchased 2,660,820 shares of common stock at an aggregate cost of $62.4 million. As of December 31, 2006, no shares remain available under the 2004 Plan, and approximately 1.3 million
Index to Financial Statements
shares remain authorized to be repurchased under the 2006 Plan. The Company may in the future make purchases of its stock pursuant to its stock repurchase plan at open market prices and may engage in private transactions, where appropriate. The repurchased shares will be available for issuance under employee benefit and stock option plans, or may be retired.
For Equity Compensation Plan Information see Part III, Item 12 - Security Ownership of Certain Beneficial Owners and Management.
Index to Financial Statements
Item 6.
Item 6.
Selected Financial Data
As of and for the following periods (in thousands except for share data):
Certain amounts presented for prior years have been reclassified to conform with the 2006 presentation.
Index to Financial Statements
Item 7.
Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
As you read this Management’s Discussion and Analysis, please refer to 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
•
Collection of fuel expense
•
Decommissioning costs and estimated asset retirement obligation
•
Future pension and other postretirement obligations
•
Reserves for tax dispute
Application of SFAS No.
As of December 31, 2006, we determined that we met the criteria to re-apply SFAS No. 71 to our Texas jurisdiction. We had previously made a determination to re-apply SFAS No. 71 to our New Mexico jurisdiction beginning July 1, 2004. This brings our accounting into line with the vast majority of regulated utilities in the United States. The factors that supported our decision are set forth in Note A to the consolidated financial statements.
Under this accounting standard, we are required to record certain costs or obligations as either assets or liabilities on our balance sheet and to 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.
At December 31, 2006 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. At December 31, 2006, we had recorded $19.9 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 will include an allowance for
Index to Financial Statements
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 will be recognized as other income and the allowance for borrowed funds used during construction will be shown as capitalized interest in our statement of operations. Under this treatment, we will 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.
Collection of Fuel Expense
In general, by law and regulation, our fuel and purchased power expenses are passed through to our customers. As discussed below, 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. 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.
Index to 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 2007.
Reserves for Tax Dispute
Our federal income tax returns for the years 1999 through 2002 have been examined by the Internal Revenue Service (“IRS”). On May 9, 2005, we received a notice of proposed deficiency from the IRS. 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. The proposed IRS adjustments go to the timing of these deductions not their ultimate deductibility for federal tax purposes. We have protested the audit adjustments through administrative appeals and believe that our treatment of the payments is supported by substantial legal authority. In the event that the IRS prevails, the resulting income tax and interest payments could be material to our cash flows. The IRS is currently performing an examination of the 2003 and 2004 income tax returns. We have established, and periodically review and re-evaluate, an estimated contingent tax liability on our consolidated balance sheet to provide for the possibility of adverse outcomes in tax proceedings. Although the ultimate outcome of the appeals case or the ongoing examination cannot be predicted with certainty, we believe that, as of December 31, 2006, adequate provision has been made for any additional tax that may be due.
Overview
The following is an overview of our results of operations for the years ended December 31, 2006, 2005 and 2004. Income for the years ended December 31, 2006, 2005 and 2004 is shown below:
Index to Financial Statements 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 2006 and 2005, 2005 and 2004, and 2004 and 2003 (in thousands):
(a) Loss on extinguishments of debt in 2006 decreased compared to 2005 and increased in 2005 compared to 2004 reflecting the refinancing of all of our first mortgage bonds in May 2005.
(b) Depreciation and amortization decreased due to completing the recovery of certain fresh-start accounting related assets over the term of the Texas Rate Stipulation which ended in July 2005.
(c) Retail base revenues increased in 2006 compared to 2005 and 2005 compared to 2004 primarily due to increased kWh sales reflecting growth in the number of customers served.
(d) A reduction in income tax expense was recorded in 2006 to recognize the change in tax rates resulting from changes in the Texas franchise (income) tax law in May 2006.
(e) Net fuel recoveries increased in 2006 compared to 2005 primarily due to the recovery of purchased power capacity payments in New Mexico in 2006 and increased recovery of transmission expenses in Texas.
(f) Net fuel recoveries increased in 2004 compared to 2003 due primarily to a Texas fuel disallowance in Docket No. 26194 which was recorded in 2003.
(g) Interest charges decreased in 2006 compared to 2005 and in 2005 compared to 2004 due to lower interest expense on long-term debt and financing obligations resulting from the refinancing of first mortgage bonds with long-term senior notes in May 2005 and the August 2005 reissuance and remarketing of pollution control bonds at lower interest rates.
(h) Palo Verde operations and maintenance expense increased in 2006 when compared to 2005 due to the repairs and modification at Unit 1 and scheduled maintenance and refueling outages at Unit 2 and Unit 3 in 2006.
(i) Palo Verde operations and maintenance expense increased in 2005 when compared to 2004 due to increased operations and maintenance expense at Unit 1 during the planned replacement of steam generators and refueling outage in late 2005, and increased administrative and general expenses.
(j) Transmission and distribution operations and maintenance expense increased primarily due to increased wheeling expenses due to the expiration of an exchange contract and increased distribution expenses.
(k) Taxes other than income taxes increased in 2006 compared to 2005 and 2005 compared to 2004 due to an increase in the El Paso city franchise fee rate which took effect in August 2005.
(l) The coal reclamation liability adjustment pertains to the updated 2004 reclamation study for the coal mine which supplies the Four Corners power plant. We had previously recorded this liability based on a 1998 study and adjusted the liability in December 2004. An additional true-up was recorded in September 2005.
(m) We abandoned the development of a customer information system project and recognized an asset impairment loss in the third quarter of 2003.
(n) A benefit was recorded in the third quarter of 2004 from a settlement of an IRS audit of our 1996-1998 tax returns.
Index to Financial Statements 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.
Operating revenues
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 City Rate Agreement, we share with our Texas customers 25% of our off-system sales margins and wheeling revenues. (See Note B of the Notes to Consolidated Financial Statements).
Revenues from the sale of electricity include fuel costs, which are essentially passed through to customers through fuel adjustment mechanisms in Texas and New Mexico and a portion through base revenues 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 revenues. 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 7.5% 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.
Retail non-fuel base revenues increased by $8.0 million or 1.9% for the twelve months ended December 31, 2005 when compared to the same period in 2004. Retail kWh sales in the twelve month period ended December 31, 2005 were 1.1% higher than the twelve month period ended December 31, 2004. Growth in the average number of retail customers served in 2005 of 2.5% accounted for most of the increase in sales. While hotter weather in the summer of 2005 (increased cooling degree days) resulted in higher sales, this was offset by milder weather conditions earlier in 2005 (decreased heating degree days).
Index to Financial Statements 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 75% 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 revenues during the May to September 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. As shown in the table below, heating and cooling degree days were generally average or below average in 2006, 2005 and 2004.
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 in the clause and to recover under-recoveries or refund over-recoveries in the clause with a two-month lag with the exception of a fixed amount of fuel costs 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
Index to Financial Statements
those costs. Natural gas prices increased significantly in 2005 and 2004. As a result, we significantly under-recovered fuel costs until we increased our fixed fuel factors in Texas in October 2005 and February 2006.
In July 2005 we filed with the Texas Commission for an increase in our fixed fuel factor and to surcharge fuel under-recoveries. A settlement allowed us, beginning in October 2005, to increase our fixed fuel factor and to surcharge $53.6 million of fuel under-recoveries over a 24-month period. In January 2006, we again filed with the Texas Commission to increase our fixed fuel factor and surcharge approximately $34 million for additional fuel under-recoveries, including interest for the period of September through November 2005, over a twelve-month period. We received Texas Commission approval to implement the new fuel factor and surcharge on an interim basis beginning with February 2006 billings. Due to these increases in our fixed fuel factor and higher kWh sales, fuel revenues recovered from Texas customers increased $52.8 million for the twelve months ended December 31, 2006 compared to 2005 and $8.6 million for the twelve months ended December 31, 2005 compared to 2004. In addition, the amount of fuel under-recoveries deferred for future collection for both the Texas and New Mexico jurisdictions declined $83.2 million for the twelve months ended December 31, 2006 compared to 2005. Fuel costs deferred for future collection increased $62.2 million for the twelve months ended December 31, 2005 compared to 2004. During 2006 and 2005, we collected $56.9 and $6.0 million of deferred fuel revenues through fuel surcharges in Texas.
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 nuclear fuel resources. Palo Verde’s availability is an important factor in realizing these off-system sales margins. 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. Off-system sales decreased $0.3 million for the twelve months ended December 31, 2005 when compared to 2004 due to a decline in energy available to sell in the off-system market because of a decline in output at the Palo Verde station due to an extended planned refueling and steam generator replacement for Unit 1 and unplanned outages at Palo Verde Units 2 and 3. Offsetting this decrease in available power were higher average market prices.
Index to Financial Statements Comparisons of kWh sales and operating revenues are shown below (in thousands):
(1) Excludes $56.9 million and $6.0 million of deferred fuel revenues recovered through Texas fuel surcharges in 2006 and 2005, respectively.
(2) Reflects increases in Texas fixed fuel factors in October 2005 and February 2006.
(3) Primarily due to increased transmission revenue.
(4) Represents revenues with no related kWh sales.
Index to Financial Statements
(1) Primarily due to reduced output from Palo Verde.
(2) Excludes $6.0 million of deferred fuel revenues recovered through Texas fuel surcharges in 2005.
(3) Primarily due to increase in recoverable fuel expenses as a result of an increase in the price and volume of natural gas burned and an increase in purchased power costs.
(4) Represents revenues with no related kWh sales.
(5) Primarily due to increased transmission revenues.
Index to Financial Statements Energy expenses
Our sources of energy include electricity generated from nuclear fuel, natural gas and coal plants that we own and purchased power. Palo Verde represents approximately 40% of our available net generating capacity and approximately 42% of our available energy for the twelve months ended December 31, 2006.
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.
Our energy expenses increased $82.0 million for the twelve months ended December 31, 2005 when compared to 2004 primarily due to (i) increased natural gas costs of $72.2 million due to increased prices and volume burned and (ii) increased costs of purchased power of $13.6 million due to higher market prices for power. These increases were partially offset in 2005 by a $0.7 million decrease to our coal reclamation liability recorded in 2005 compared to a $2.2 million increase in our coal reclamation costs recorded in 2004.
(a) Excludes a reduction of $0.7 million and an increase of $2.2 million to our coal reclamation liability recorded in 2005 and 2004, respectively.
(b) Excludes a $0.7 million contract termination fee.
Index to Financial Statements Other operations expense
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.
Other operations expense increased $4.8 million, or 2.7% in 2005 compared to 2004 primarily due to (i) increased Palo Verde expense of $3.1 million; (ii) increased other postretirement benefit costs of $2.0 million; and (iii) increased wheeling costs of $1.9 million. These increases were partially offset by decreased regulatory expense of $1.1 million related to FERC matters and the receipt of a sales tax refund of $0.9 million in 2005 with no comparable activity in 2004.
Maintenance expense
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.
Maintenance expense increased $2.1 million, or 4.8% in 2005 compared to 2004 primarily due to increased environmental expenses of $1.2 million related to remediation projects and increased maintenance at Palo Verde of $0.4 million.
Depreciation and amortization expense
Depreciation and amortization expense decreased $14.0 million and $10.9 million in 2006 compared to 2005 and in 2005 compared to 2004, respectively, primarily due to completing the recovery of certain fresh-start accounting related assets over the term of the Texas Rate Stipulation which ended in July 2005. These decreases were 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 increased $5.5 million in 2006 compared to 2005 and increased by $2.4 million in 2005 compared to 2004 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. The increase in 2005 compared to 2004 was partially offset by a decrease in New Mexico occupation street rental tax. As a result of a June 2004 change in New Mexico law, the occupation street rental tax on retail sales of electricity is now collected directly from retail customers and not recorded as an expense.
Index to Financial Statements Other income (deductions)
Other income (deductions) increased $20.7 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.
Other income (deductions) decreased $12.8 million in 2005 compared to 2004 primarily due to an increase in the loss on extinguishment of debt of $14.2 million, as a result of the refinancing of our first mortgage bonds in the second quarter of 2005. This decrease was partially offset by increased interest income in 2005 of $2.2 million primarily related to a $1.1 million adjustment to reduce interest income associated with the resolution of the Texas fuel reconciliation in PUC Docket No. 26194 recorded in 2004 with no comparable activity in 2005, and the receipt of $0.6 million interest related to a sales tax refund in 2005.
Interest charges (credits)
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 $0.9 million reduction in capitalized interest as a result of completing construction of new Palo Verde Unit 1 steam generators in December 2005.
Interest charges (credits) decreased $10.6 million in 2005 compared to 2004 due to an $8.4 million decrease in interest on long-term debt and financing obligations resulting from the debt refinancing in 2005. The decrease was also due to increased capitalized interest of $2.4 million due to an increase in construction work in progress related to Palo Verde Unit 1 and Unit 3 steam generators.
Income tax expense
Income tax expense, before extraordinary item and the cumulative effect of an accounting change, increased $7.5 million in 2006 compared to 2005 primarily due to increased pretax income and certain permanent tax differences. The increase in income tax expense in 2006 compared to 2005 was offset by a reduction in state income taxes resulting from a change in the Texas franchise (income) tax law in 2006 as discussed below. Income tax expense, before extraordinary item and the cumulative effect of an accounting change, increased $9.4 million in 2005 as compared to 2004 primarily due to the $6.2 million benefit from the IRS settlement recorded in the third quarter of 2004 and for changes in pretax income and certain permanent differences.
Index to Financial Statements 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 will result 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 includes: (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.
Extraordinary gain
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 the Texas jurisdiction at December 31, 2006 as described under SFAS No. 71 below.
The extraordinary gain on re-application of SFAS No. 71 for 2004 relates to our third quarter 2004 determination that we met the criteria necessary to re-apply SFAS No. 71 to our New Mexico jurisdiction. The decision was based on our receiving the NMPRC’s approval for new rates that were based upon our cost of service and the fact that New Mexico had repealed its electric utility restructuring law. The re-application of SFAS No. 71 to our New Mexico jurisdiction resulted in the recording of a $1.8 million extraordinary gain, net of tax, in the third quarter of 2004.
Cumulative effect of accounting change
The cumulative effect of accounting change for 2005 of $1.1 million, 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.
Index to Financial Statements 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 utility’s balance sheet if the regulator provides assurance that these costs will be charged to and collected from the utility’s customers (or has already permitted such cost recovery). The resulting regulatory assets or liabilities are amortized in subsequent periods based upon their respective amortization periods in a utility’s cost of service.
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 a new rate agreement with the City of El Paso (“City Rate Agreement”). Under the City Rate Agreement most retail base rates remain at their current level for the next five years. If, during the term of the agreement, 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, at the City’s direction, an amount equal to 50% of the pre-tax return in excess of the ceiling. The City Rate Agreement required the approval of the Texas Commission to implement the fuel related provisions of the agreement 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 City Rate Agreement and extending the rate freeze and earnings sharing provisions of the agreement to all customers in Texas based upon settlements with parties to the proceeding. Based upon the City Rate Agreement and order of the Texas Commission extending the agreement to all customers in Texas, we determined that our Texas jurisdiction meets 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 changes in our cost structure result in our rates fully recovering our cost of providing service, and the earnings sharing provisions of the rate agreement 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 the City and Texas Commission.
As a result of the re-application of SFAS No. 71 to our Texas jurisdiction at December 31, 2006, we have 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 will 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 will be recognized as income and the allowance for borrowed funds used during construction will be 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.”
Index to Financial Statements 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. We do not believe SFAS No. 157 will have a significant impact on our consolidated financial statements.
In June 2006, the FASB issued FASB Interpretation No. 48 (“FIN 48”), “Accounting for Uncertainty in Income Taxes - an interpretation of FASB Statement No. 109.” FIN 48 clarifies the accounting for uncertainty in income taxes recognized in the financial statements in accordance with SFAS No. 109, “Accounting for Income Taxes.” FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return and provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. FIN 48 is effective for fiscal years beginning after December 15, 2006. We will adopt the provisions of this interpretation in our financial statements for the fiscal year beginning January 1, 2007. We do not believe FIN 48 will have a significant impact on our consolidated financial statements.
In September 2006, the SEC Staff issued Staff Accounting Bulletin No. 108 (“SAB No. 108”), “Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in the Current Year Financial Statements.” SAB No. 108 requires the use of two alternative approaches in quantitatively evaluating materiality of misstatements. If the misstatement as quantified under either approach is material to the current year financial statements, the misstatement must be corrected. If the effect of correcting the prior year misstatements, if any, in the current year income statement is material, the prior year financial statements should be corrected. SAB No. 108 is effective for fiscal years ending after November 15, 2006. We adopted the provisions of SAB No. 108 in the fourth quarter of 2006 and it did not affect our consolidated financial statements.
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 related to our generating facilities and transmission and distribution systems, operating expenses including fuel costs and taxes. We expect that cash flows from operations will be used to fund a significant portion of these capital requirements. As of December 31, 2006, we had approximately $40.1 million in cash and cash equivalents, an increase of $32.1 million from the balance of $8.0 million on December 31, 2005.
Capital Requirements. Substantial increases in the cost of natural gas during 2004 and 2005 and the delay in reflecting higher fuel costs in fixed fuel factors in Texas led to the under-recovery of the Texas jurisdictional portion of our fuel costs by $84.9 million, including interest, for the period from March 2004 to December 2005. In November 2005, the Texas Commission approved a settlement of a
Index to Financial Statements
fuel factor filing which provided for (i) a surcharge over a 24-month period of fuel under-recoveries of $53.6 million, including interest through August 2005; and (ii) new fuel factors which reflect natural gas costs of $7.28 per MMBtu. We had previously been permitted to implement the increase in the fuel factor and the fuel surcharge on an interim basis beginning with October 2005 billings.
In January 2006, we filed a request with the Texas Commission for an additional increase in our fixed fuel factors reflecting gas costs of $9.35 per MMBtu, and to surcharge over a twelve-month period approximately $34 million for fuel under-recoveries, including interest, for the period September 2005 to November 2005. The requested fuel factor and fuel surcharge were placed into effect with February 2006 bills to customers. Recovery of this fuel surcharge was completed in January 2007. In February 2007, we lowered our fixed fuel factors by 10% to reflect recent reductions in natural gas costs. For the twelve months ended December 31, 2006, we under-recovered fuel costs in Texas by approximately $1.0 million. In addition, we collected $56.9 million in fuel surcharges in the twelve months ended December 31, 2006, reducing our deferred fuel balance and increasing cash flow by $55.9 million. We should continue to realize increased cash flow as we collect these fuel surcharges during 2007.
Our long-term liquidity requirements consist primarily of construction of electric utility plant and the payment of interest on debt. 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, including replacing steam generators in Palo Verde Unit 3. 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.
During the twelve months ended December 31, 2006, we utilized $89.2 million of federal income tax loss carryforwards and $42.0 million of state income tax loss carryforwards reflecting the collection of deferred fuel and increase in pre-tax income. As deferred fuel costs are collected from customers, they are included in taxable income. Our future cash flow requirements for federal and state income taxes are expected to increase over that required in recent years.
We continually evaluate our funding requirements related to our retirement plans, other postretirement benefit plans, and decommissioning trust funds. We contributed $13.7 million and $19.9 million to our retirement plans during the twelve months ended December 31, 2006 and 2005, respectively. We also contributed $3.4 million to our other postretirement benefit plan for both 2006 and 2005 and $6.7 million and $6.2 million to our decommissioning trust funds during the twelve months ended December 31, 2006 and 2005, respectively.
The Company does not pay dividends on common stock. Since 1999, we have repurchased approximately 18.0 million shares of common stock at an aggregate cost of $238 million, including commissions. In September 2006, the Board authorized the repurchase of up to 2.3 million shares of our outstanding common stock. The shares authorized under the 2006 Plan are in addition to the shares which were available under a buy back program previously approved by the Board in February 2004. During 2006, we repurchased 2,660,820 shares of common stock at an aggregate cost of $62.4 million. As of December 31, 2006, no shares remain available under the 2004 Plan, and approximately 1.3 million shares remain authorized to be repurchased under the 2006 Plan. We may in the future make purchases of our stock 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
Index to Financial Statements
benefit and stock option 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 47.6% as of December 31, 2006.
Capital Sources. As discussed in our 2005 Form 10-K, we issued senior notes in May 2005 to fund the reacquisition of our first mortgage bonds which resulted in significant savings in interest costs. In addition, in August 2005, we reissued and remarketed pollution control bonds resulting in a significant savings in interest costs.
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 Moody’s and “BBB” by Standard & Poors. Construction expenditures are expected to increase as we plan to add new generation capacity in 2009 and subsequent years. We expect to initially fund most of our construction expenditures with internally generated funds and, when appropriate, the issuance of long-term debt, consistent with maintaining a capital structure typical of a regulated electric utility. Due to the increased volatility in the natural gas markets we expanded our existing revolving credit facility from $100 million to $150 million in 2006. The expansion came at a time of heightened competition in the bank markets resulting in lower borrowing costs under the new facility. The revolving credit facility will continue to provide for up to $70 million for nuclear fuel purchases with any amounts not borrowed for nuclear fuel available for working capital purposes.
Index to Financial Statements Contractual Obligations. Our contractual obligations as of December 31, 2006 are as follows (in thousands):
(1) Two series of pollution control bonds are remarketed and the interest rates are set weekly. The remaining two series of pollution control bonds are scheduled for remarketing and/or mandatory tender in 2012 and 2040.
(2) Reflects current obligations under the $150 million credit facility used to finance nuclear fuel including interest based on actual interest rates at the end of 2006.
(3) Amount is based on the minimum volumes per the contract and market price at the end of 2006. Gas obligation includes a gas storage contract and a gas transportation contract.
(4) Some of the nuclear fuel contracts are based on a fixed price adjusted for an index. The index used is the current index at the end of 2006.
(5) These obligations include our minimum contractual funding requirements for the non-qualified retirement income plan and the other postretirement benefits for 2007. We have no minimum contractual funding requirement related to our retirement income plan for 2007. However, we may decide to fund at higher levels and expect to contribute $13.6 million and $3.4 million to our retirement plans and postretirement benefit plan in 2007, as disclosed in Part II, Item 8, Notes to Consolidated Financial Statements, Note K, Employee Benefits. Minimum contractual funding requirements for 2008 and beyond are not included due to the uncertainty of interest rates and the related return on assets.
(6) These obligations represent funding requirements under the ANPP Participation Agreement based on the current rate of return on investments.
(7) The Company leases executive and administrative offices in El Paso, Texas under a lease which expires in May 2007. The Company is currently in negotiations regarding this lease. In addition, the Company leases certain warehouse facilities in El Paso, Texas under a lease which expires in January 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 seven years.
Index to Financial Statements 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.
Index to Financial Statements
Item 7A.
Item 7A.
Quantitative and Qualitative Disclosures About Market Risk
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, 2006, the variable interest rates were 3.85% for both the $63.5 million and the $37.1 million pollution control bond series. A hypothetical 10% increase in interest rates, annualized from the December 31, 2006 rate, would cause an approximate $0.4 million increase in interest expense.
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, except as noted in “Regulation - New Mexico Regulatory Matters - Fuel,” are passed through to 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 $45.6 million and $39.3 million as of December 31, 2006 and 2005, respectively. A hypothetical 10% increase in interest rates would reduce the fair values of these funds by $0.7 million and $0.6 million based on their fair values at December 31, 2006 and 2005, respectively.
Equity Price Risk
Our decommissioning trust funds include marketable equity securities of approximately $69.1 million and $56.7 million at December 31, 2006 and 2005, respectively. A hypothetical 20% decrease in equity prices would reduce the fair values of these funds by $13.8 million and $11.3 million based on their fair values at December 31, 2006 and 2005, respectively.
Index to Financial Statements 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, 2007, 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.
Index to Financial Statements Management Report on Internal Control Over Financial Reporting
The Company’s management is responsible for establishing and maintaining adequate internal control over financial reporting. Internal control over financial reporting is defined in Rule 13a-15(f) or 15d-15(f) promulgated under the Securities Exchange Act of 1934 as a process designed by, or under the supervision of, the Company’s principal executive and principal financial officers and affected by the Company’s board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles and includes those policies and procedures that:
•
Pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the assets of the Company;
•
Provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and the receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and
•
Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
The Company’s management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2006. In making this assessment, the Company’s management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) in Internal Control-Integrated Framework.
Based on its assessment, management believes that, as of December 31, 2006, the Company’s internal control over financial reporting is effective based on those criteria.
The Company’s independent registered public accounting firm, KPMG LLP, has issued an audit report on management’s assessment of the Company’s internal control over financial reporting. This report appears on page 55 of this report.
Index to Financial Statements
Item 8.
Item 8.
Financial Statements and Supplementary Data
INDEX TO FINANCIA L STATEMENTS
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, 2006 and 2005, 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, 2006. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of El Paso Electric Company and subsidiary as of December 31, 2006 and 2005, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2006, in conformity with U.S. generally accepted accounting principles.
As discussed in Note D, effective December 31, 2005, the Company adopted Financial Accounting Standards Board Interpretation No. 47, Accounting for Conditional Asset Retirements, and as discussed in Note A, the Company adopted Statement of Financial Accounting Standards No. 123(R), Share-Based Payment, effective January 1, 2006, and as discussed in Note K, the Company adopted Statement of Financial Accounting Standards No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, effective December 31, 2006.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of El Paso Electric Company’s internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 27, 2007 expressed an unqualified opinion on management’s assessment of, and the effective operation of, internal control over financial reporting.
KPMG LLP
Houston, Texas
February 27, 2007
Index to Financial Statements Report of Independent Registered Public Accounting Firm
The Board of Directors and Shareholders
El Paso Electric Company:
We have audited management’s assessment, included in the accompanying Management Report on Internal Control Over Financial Reporting, that El Paso Electric Company maintained effective internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commissions (COSO). El Paso Electric Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, management’s assessment that El Paso Electric Company maintained effective internal control over financial reporting as of December 31, 2006, is fairly stated, in all material respects, based on criteria established in Internal Control-Integrated Framework issued by COSO. Also, in our opinion, El Paso Electric Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control-Integrated Framework issued by COSO.
Index to Financial Statements We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of El Paso Electric Company and subsidiary as of December 31, 2006 and 2005, 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, 2006, and our report dated February 27, 2007 expressed an unqualified opinion on those consolidated financial statements.
KPMG LLP
Houston, Texas
February 27, 2007
Index to Financial Statements EL PASO ELECTRIC COMPANY AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
See accompanying notes to consolidated financial statements.
Index to Financial Statements EL PASO ELECTRIC COMPANY AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS (Continued)
See accompanying notes to consolidated financial statements.
Index to Financial Statements EL PASO ELECTRIC COMPANY AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands except for share data)
See accompanying notes to consolidated financial statements.
Index to Financial Statements EL PASO ELECTRIC COMPANY AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF COMPREHENSIVE OPERATIONS
(In thousands)
See accompanying notes to consolidated financial statements.
Index to Financial Statements EL PASO ELECTRIC COMPANY AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCK EQUITY
(In thousands except for share data)
See accompanying notes to consolidated financial statements.
Index to Financial Statements EL PASO ELECTRIC COMPANY AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
See accompanying notes to consolidated financial statements.
Index to Financial Statements
I NDEX TO NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Index to Financial Statements EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
A. Summary of Significant Accounting Policies
General. El Paso Electric Company is a public utility engaged in the generation, transmission and distribution of electricity in an area of approximately 10,000 square miles in west Texas and southern New Mexico. El Paso Electric Company also serves wholesale customers in Texas and periodically in the Republic of Mexico.
Principles of Consolidation. The consolidated financial statements include the accounts of El Paso Electric Company and its wholly-owned subsidiary, MiraSol Energy Services, Inc. (“MiraSol”) (collectively, the “Company”). MiraSol, which began operations as a separate subsidiary in March 2001, provided energy efficiency products and services previously provided by the Company’s Energy Services Business Group. On July 19, 2002, all sales activities of MiraSol ceased. MiraSol remains a going concern in order to satisfy current contracts and warranty and service obligations on previously installed projects. See Note I. All intercompany transactions and balances have been eliminated in consolidation.
Use of Estimates. The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Basis of Presentation. The Company maintains its accounts in accordance with the Uniform System of Accounts prescribed by the Federal Energy Regulatory Commission (the “FERC”).
Application of SFAS No. 71. Regulated electric utilities typically prepare their financial statements in accordance with SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation.” Under this accounting standard, certain recoverable costs are shown as either assets or liabilities on a utility’s balance sheet if the regulator provides assurance that these costs will be charged to and collected from the utility’s customers (or has already permitted such cost recovery). The resulting regulatory assets or liabilities are amortized in subsequent periods based upon their respective amortization periods in a utility’s cost of service. The Company did not apply SFAS No. 71 to the Company’s financial statements upon emerging from bankruptcy. This decision was based on the Company’s determination that the Company’s rates were no longer designed to recover the Company’s costs of providing service to customers.
During 2004, the Company determined that it met the criteria necessary to re-apply SFAS No. 71 to the Company’s New Mexico jurisdictional operations. Two key events transpired in New Mexico that, when considered together, resulted in the Company’s decision to re-apply SFAS No. 71. In April of 2004, the Company received a final order approving a unanimous stipulation which established new base and fuel rates for the Company’s New Mexico customers which were implemented June 1, 2004. The
Index to Financial Statements EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Company’s approved rates were based upon the Company’s cost of providing service in New Mexico. That event, coupled with the repeal of New Mexico’s electric utility industry restructuring law in April of 2003, resulted in the Company meeting the criteria for the re-application of SFAS No. 71 to New Mexico, beginning July 1, 2004. The re-application of SFAS No. 71 to the Company’s New Mexico jurisdiction resulted in the recording in 2004 of $18.5 million of regulatory assets, $5.0 million in related accumulated deferred income tax assets, $16.2 million of regulatory liabilities, $5.5 million in related accumulated deferred tax liabilities and a $1.8 million extraordinary gain, net of tax, or $0.04 basic and diluted earnings per share.
The Company’s Texas jurisdiction had been operating under a rate freeze which expired on July 31, 2005. In July 2005, the Company entered into a new rate agreement with the City of El Paso (“City Rate Agreement”). Under the City Rate Agreement most retail base rates remain at their current level for the next five years. If, during the term of the agreement, the Company’s return on equity falls below the bottom of a defined range, reflecting regulatory returns on equity, the Company has the right to initiate a rate case and seek an adjustment to base rates. If the Company’s return on equity exceeds the top of the range, the Company will refund, at the City’s direction, an amount equal to 50% of the pre-tax return in excess of the ceiling. The City Rate Agreement required the approval of the Texas Commission to implement the fuel related provisions of the agreement including the sharing of 25% of off-system sales margins with customers through the Company’s fixed fuel factor.
On December 8, 2006, the Texas Commission issued a final order approving the fuel related provisions of the City Rate Agreement and extending the rate freeze and earnings sharing provisions of the agreement to all customers in Texas based upon settlements with parties to the proceeding. Based upon the City Rate Agreement and order of the Texas Commission extending the agreement to all customers in Texas, the Company determined that the Company’s Texas jurisdiction meets the criteria for the re-application of SFAS No. 71 to the Company’s Texas jurisdiction as of December 31, 2006.
The re-application of SFAS No. 71 to the Company’s Texas jurisdiction recognizes that changes in the Company’s cost structure result in the Company’s rates fully recovering the Company’s cost of providing service, and the margin sharing provisions of the rate agreement provide for continued recovery of the Company’s 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 the Company’s Texas service territory and the continued regulation of the Company’s retail rates by the City and Texas Commission.
As a result of the re-application of SFAS No. 71 to the Company’s Texas jurisdiction at December 31, 2006, the Company has recorded regulatory assets of $9.6 million, related accumulated deferred income tax liability of $3.5 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
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accounting requirements, the Company will 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 will be recognized as income and the allowance for borrowed funds used during construction will be shown as capitalized interest charges in the Company’s statement of operations. Prior to the re-application of SFAS No. 71, the Company capitalized interest costs in accordance with SFAS No. 34, “Capitalization of Interest Costs.”
Comprehensive Income. Certain gains and losses that are not recognized currently in the consolidated statements of operations are reported as other comprehensive income in accordance with SFAS No. 130, “Reporting Comprehensive Income.”
Utility Plant. Depreciation is provided on a straight-line basis over the estimated remaining lives of the assets (ranging from 5 to 31 years), except for approximately $298 million of reorganization value allocated primarily to net transmission, distribution and general plant in service. This amount was depreciated on a straight-line basis over the ten-year period of the Texas Rate Stipulation which ended in July 2005. For all other utility plant, Texas and New Mexico depreciation lives are the same.
The Company charges the cost of repairs and minor replacements to the appropriate operating expense accounts and capitalizes the cost of renewals and betterments. When property subject to composite depreciation is retired or otherwise disposed of in the normal course of business, its original cost - together with the cost of removal, less salvage - is charged to accumulated depreciation. For other property dispositions, the applicable cost and accumulated depreciation is removed from the balance sheet accounts and a gain or loss is recognized.
The cost of nuclear fuel is amortized to fuel expense on a units-of-production basis. A provision for spent fuel disposal costs is charged to expense based on requirements of the Department of Energy (the “DOE”) for disposal cost of approximately one-tenth of one cent on each kWh generated. The Company is also amortizing its share of costs associated with on-site spent fuel storage casks at Palo Verde over the burn period of the fuel that will necessitate the use of the storage casks. See Note C.
Impairment of Long-Lived Assets. In accordance with SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” long-lived assets, such as property, plant, and equipment and purchased intangibles subject to amortization, are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to estimated undiscounted future cash flows expected to be generated by the asset. If the carrying amount of an asset exceeds its estimated undiscounted future cash flows, an impairment charge is recognized for the amount by which the carrying amount of the asset exceeds the fair value of the asset.
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Capitalized Interest. The Company capitalizes interest cost to construction work in progress and nuclear fuel in process in accordance with SFAS No. 34, “Capitalization of Interest Cost” for its Texas jurisdictional operations prior to December 31, 2006. For its New Mexico jurisdictional operations, the Company capitalizes interest and common equity costs to construction work in progress and nuclear fuel in process in accordance with the FERC Uniform System of Accounts as provided for in SFAS No. 71. The amount of the equity component of the AFUDC capitalized to construction work in progress was $0.9 million for the years ended December 31, 2006 and 2005.
Asset Retirement Obligation. The Company complies with SFAS No. 143, “Accounting for Asset Retirement Obligations.” SFAS No. 143 sets forth accounting requirements for the recognition and measurement of liabilities associated with the retirement of tangible long-lived assets. An asset retirement obligation (“ARO”) associated with long-lived assets included within the scope of SFAS No. 143 is that for which a legal obligation exists under enacted laws, statutes, written or oral contracts, including obligations arising under the doctrine of promissory estoppel. Under the statement, these liabilities are recognized as incurred if a reasonable estimate of fair value can be established and are capitalized as part of the cost of the related tangible long-lived assets. The Company records the increase in the ARO due to the passage of time as an operating expense (accretion expense). Effective December 31, 2005, the Company adopted FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations,” (“FIN 47”). FIN 47 clarifies that the term “conditional” as used in SFAS No. 143, refers to a legal obligation to perform an asset retirement activity even if the timing and/or settlement are conditional on a future event that may or may not be within the control of an entity. See Note D.
Cash and Cash Equivalents. All temporary cash investments with an original maturity of three months or less are considered cash equivalents.
Investments. The Company’s marketable securities, included in decommissioning trust funds in the balance sheets, are reported at fair market value and consist primarily of equity securities and municipal, federal and corporate bonds in trust funds established for decommissioning of its interest in Palo Verde. Such marketable securities are classified as “available-for-sale” securities and, as such, unrealized gains and losses are included in accumulated other comprehensive income as a separate component of common stock equity. However, if declines in fair value of marketable securities below original cost basis are determined to be other than temporary, then the declines are reported as losses in the consolidated statement of operations and a new cost basis is established for the affected securities at fair value. Gains and losses are determined using the cost of the security based on the specific identification basis. See Note M.
Derivative Accounting. The Company complies with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended by SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities,” including any effective implementation guidance discussed by the FASB Derivatives Implementation Group. This standard requires the recognition of
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derivatives as either assets or liabilities in the balance sheet with measurement of those instruments at fair value. Any changes in the fair value of these instruments are recorded in earnings or other comprehensive income. See Note M.
Inventories. Inventories, primarily parts, materials, supplies, fuel oil and natural gas are stated at average cost not to exceed recoverable cost.
Operating Revenues Net of Energy Expenses. The Company accrues revenues for services rendered, including unbilled electric service revenues. Energy expenses are stated at actual cost incurred. The Company’s Texas retail customers are presently being billed under a fixed fuel factor approved by the Public Utility Commission of Texas (“Texas Commission”). The Company’s New Mexico retail customers are being billed under base rates and a fuel adjustment clause which is adjusted monthly, as approved by the New Mexico Public Regulation Commission (“NMPRC”). The Company’s recovery of energy expenses in these jurisdictions is subject to periodic reconciliations of actual energy expenses incurred to actual fuel revenues collected. The difference between energy expenses incurred and fuel revenues charged to the Company’s Texas and New Mexico customers, as determined under Texas Commission and NMPRC rules, is reflected as net over/undercollection of fuel revenues in the consolidated balance sheets. See Note B. Amounts not expected to be collected within the next twelve months are classified as “undercollection of fuel revenues, non-current.”
Unbilled Revenues. Accounts receivable include accrued unbilled revenues of $18.0 million and $16.4 million at December 31, 2006 and 2005, respectively.
Allowance for Doubtful Accounts. Additions, deductions and balances for allowance for doubtful accounts for 2006, 2005 and 2004 are as follows (in thousands):
Income Taxes. The Company accounts for federal and state income taxes under the asset and liability method of accounting for income taxes. Under this method, deferred income taxes are recognized for the estimated future tax consequences of “temporary differences” by applying enacted statutory tax rates for each taxable jurisdiction applicable to future years to differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities. The Company records a valuation allowance to reduce its deferred tax assets to the extent it is more likely than not that
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such deferred tax assets will not be realized. The effect on deferred tax assets and liabilities of a change in tax rate is recognized in income in the period that includes the enactment date.
Earnings per Share. Basic earnings per share is computed by dividing net income by the weighted average number of shares outstanding. Diluted earnings per share is computed by dividing net income by the weighted average number of shares and the dilutive impact of the sum of unvested restricted stock, performance shares, and the stock options that were outstanding during the period with the amount of outstanding options calculated by using the treasury stock method.
Stock-Based Compensation. The Company has two stock-based long-term incentive plans. Effective January 1, 2006, the Company adopted SFAS No. 123 (revised) “Accounting for Stock-Based Compensation,” which requires a public entity to measure the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award (with some limited exceptions). Such cost will be recognized over the period during which an employee is required to provide service in exchange for the award (the “requisite service period”) which typically will be the vesting period. Compensation cost is not recognized for anticipated forfeitures prior to vesting of equity instruments. SFAS No. 123 (revised) applies to all awards granted after January 1, 2006 and to awards modified, repurchased or cancelled after that date. Additionally, compensation cost for outstanding awards for which the requisite service has not been rendered as of January 1, 2006 shall be expensed as the requisite service is rendered on or after such date. The compensation cost for that portion of awards shall be based on the grant-date fair value of those awards as calculated for pro forma disclosure under SFAS No. 123. SFAS No. 123 (revised) replaces SFAS No. 123, “Accounting for Stock - Based Compensation,” and supersedes APB Opinion No. 25, “Accounting for Stock Issued to Employees,” and related interpretations. See Note E.
If compensation expense for the incentive plans had been amortized on a straight-line basis over the vesting period, consistent with the provisions of SFAS No. 123 (revised), the Company’s net earnings and earnings per share for 2005 and 2004 would have been reduced to the proforma amounts presented below (in thousands, except for per share data):
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Prior to the adoption of SFAS No. 123 (revised), the Company presented all tax benefits for deductions resulting from the exercise of share-based compensation as operating cash flows in the Condensed Consolidated Statement of Cash Flows. SFAS No. 123 (revised) requires the benefits of tax deductions in excess of the taxes expensed on recognized compensation cost to be reported as financing cash flows.
Other 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. The Company does not believe SFAS No. 157 will have a significant impact on the Company’s consolidated financial statements.
In June 2006, the FASB issued FASB Interpretation No. 48 (“FIN 48”), “Accounting for Uncertainty in Income Taxes - an interpretation of FASB Statement No. 109.” FIN 48 clarifies the accounting for uncertainty in income taxes recognized in the financial statements in accordance with SFAS No. 109, “Accounting for Income Taxes.” FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return and provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. FIN 48 is effective for fiscal years beginning after December 15, 2006. The Company will adopt the provisions of this interpretation in the Company’s financial statements for the fiscal year beginning January 1, 2007. The Company does not believe FIN 48 will have a significant impact on the Company’s consolidated financial statements.
In September 2006, the SEC Staff issued Staff Accounting Bulletin No. 108 (“SAB No. 108”), “Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in the Current Year Financial Statements.” SAB No. 108 requires the use of two alternative approaches in quantitatively evaluating materiality of misstatements. If the misstatement as quantified under either approach is material to the current year financial statements, the misstatement must be corrected. If the effect of correcting the prior year misstatements, if any, in the current year income statement is material, the prior year financial statements should be corrected. SAB No. 108 is effective for fiscal years ending after November 15, 2006. The Company adopted the provisions of SAB No. 108 in the fourth quarter of 2006 and it did not affect the Company’s consolidated financial statements.
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Pension and Postretirement Benefit Accounting. For a full discussion of the Company’s accounting policies for its employee benefits. See Note K.
Reclassification. Certain amounts in the consolidated financial statements for 2005 and 2004 have been reclassified to conform with the 2006 presentation.
B. Regulation
General
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 Company’s wholesale transactions. The decisions of the Texas Commission, NMPRC and the FERC are subject to judicial review.
Texas Regulatory Matters
Texas Freeze Period and Franchise Agreement. On July 21, 2005, the Company entered into an agreement with the City (the “City Rate Agreement”) to extend its existing freeze period for an additional five years expiring June 30, 2010 (the “Texas Freeze Period”). Under the City Rate Agreement which became effective as of July 1, 2005, most retail base rates will remain at their current level through June 30, 2010. If, during the term of the agreement, the Company’s 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 Company’s return on equity exceeds the top of the range, the Company will refund, at the City’s direction, an amount equal to 50% of the pre-tax return in excess of the ceiling. The range is market-based, and at current rates, would be a range of approximately 8.3% to 12.3%.
Pursuant to the City Rate Agreement, the Company will share with its Texas customers 25% of off-system sales margins and wheeling revenues. 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”). On December 8, 2006, the Texas Commission approved the margin sharing provisions of the City Rate Agreement in PUC Docket No. 32289 pursuant to settlement agreements in that docket.
Index to Financial Statements EL PASO ELECTRIC COMPANY AND SUBSIDIARY
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In PUC Docket No. 32289, the Company entered into settlement agreements with the Texas Commission Staff, a large industrial customer, the City, 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 Company’s support of low-income energy efficiency programs; and (iv) provides that after the expiration of the City Rate Agreement, 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 the end of the City Rate Agreement on 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 City Rate Agreement, 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, the City, 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.
Under the terms of the City Rate Agreement, the Company has committed to spend at least 0.3% of its El Paso revenues on civic and charitable causes within the City. The Company and the City also engaged, at the Company’s expense, the services of an independent consultant to review the reasonableness of certain operating expenses of the Company. In June 2006, the consultant issued its report stating that such expenses were reasonable and, as a result, the City Rate Agreement remained in full force and effect. The City Rate Agreement may also be reopened by the City in the event of a company merger to seek rate reductions based on post-merger synergy savings.
The City also granted to the Company a new 25-year franchise which became effective August 2, 2005 and increased franchise fee payments from 2% to 3.25% of gross receipts earned within the City limits. The franchise governs the Company’s usage of City-owned property and the payment of franchise fees. In August 2005, a dispute rose over the timing and characterization of past and future franchise fee payments to the City. The Company has continued to make payments in accordance with the terms of the agreement while parties discuss a resolution of this issue. The Company does not believe that such resolution will have a material adverse impact on its results of operations or financial condition.
Fuel and Purchased Power Costs. Although the Company’s base rates are frozen under the City Rate Agreement, pursuant to Texas Commission rules and the City Rate Agreement, the Company’s fuel costs including purchased power energy costs are passed through to 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. Pursuant to Texas Commission rules, the Company must file a fuel reconciliation for the three-year period ending February 28, 2007 by August 31, 2007.
Index to Financial Statements EL PASO ELECTRIC COMPANY AND SUBSIDIARY
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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 as a result of higher natural gas prices. 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 Commission’s decision in PUC Docket No. 32289, the margin sharing proceeding 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 30, 2007. The settlement requests 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% 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. The new fuel factors were approved on an interim basis and placed into effect in customer bills in February 2007. The settlement is subject to final approval by the Texas Commission which is expected in March 2007.
Palo Verde Performance Standards. The Texas Commission established performance standards for the operation of Palo Verde pursuant to which each Palo Verde unit is evaluated annually to determine whether its three-year rolling average capacity factor entitles the Company to a reward or subjects it to a penalty. The capacity factor is calculated as the ratio of actual generation to maximum possible generation. If the capacity factor, as measured on a station-wide basis for any consecutive 24-month period, should fall below 35%, the parties to the City Rate Agreement can seek different rate treatment for Palo Verde. The removal of Palo Verde from rate base could have a significant negative impact on the Company’s revenues and financial condition. The Company has calculated the performance rewards for the reporting periods ending in 2006 and 2004 to be approximately $0.4 million and $0.2 million, respectively. The 2006 and 2004 rewards will be included along with energy costs incurred and fuel revenue billed as part of the Texas Commission’s review during a future periodic 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 Company’s books until the Texas Commission has ordered a final determination in a fuel proceeding or comparable evidence of collectibility is obtained. Performance penalties are recorded when assessed as probable by the Company.
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 Commission order adopting this agreement, the Company made a payment in November 2004 in the amount of $5.8 million to El Paso County General Assistance Agency and Big Bend Community Center Committee, Inc. In further compliance with the
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Texas Commission’s order, the Company sought and received approval by the El Paso City Council in January 2006 to remit to the City approximately $5.8 million in Palo Verde performance reward funds to fund demand side management programs as requested such as weatherization with a focus on programs to assist small business and commercial customers. As of December 31, 2006 $6.0 million, including accrued interest, remains to be paid under these agreements and is recorded as a liability of the Company’s 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. The Texas Restructuring Law, however, specifically recognized and preserved the Company’s Texas Rate Stipulation and Texas Settlement Agreement by, among other things, exempting the Company’s Texas service area from retail competition until the end of the Freeze Period. On October 13, 2004, the Texas Commission approved a rule further delaying retail competition in the Company’s Texas service territory. The rule approved by the Texas Commission sets a schedule which identifies various milestones for the Company to reach before competition can begin. The first milestone calls for the development, approval by the FERC, and commencement of independent operation of an RTO in the area that includes the Company’s 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 Commission’s final evaluation of the market’s readiness to offer fair competition and reliable service to all retail customers. The Company believes that adoption of this rule will likely delay retail competition in El Paso for a number of years. There is substantial uncertainty about both the regulatory framework and market conditions that will exist if and when retail competition is implemented in the Company’s service territory, and the Company may incur substantial preparatory, restructuring and other costs that may not ultimately be recoverable. There can be no assurance that deregulation would not adversely affect the future operations, cash flows and financial condition of the Company.
Renewables and Energy Efficiency Programs. Notwithstanding the Texas Commission’s approval of a rule further delaying competition in the Company’s 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 will have to annually obtain its pro rata share of renewable energy credits as determined by the Program Administrator (the Electric Reliability Council of Texas). The Company’s ultimate obligation to obtain renewable energy credits will not be known until January 31 of the year following the compliance year, and it will have until March 31 to obtain, if necessary, and submit to the Program Administrator, sufficient credits. The Company obtained the required renewable energy credits to meet its expected obligations through 2006. In addition, beginning in 2006, the Company was required to fund incentives for energy efficiency savings that will achieve the goal of meeting 5% of its Texas jurisdiction growth in demand through energy efficiency savings. The goal is increased to 10% of the Company’s Texas jurisdiction growth in
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demand annually beginning January 1, 2008. For the plan year ended December 31, 2006, the Company incurred expenditures for incentives of approximately $0.6 million. Pursuant to the Company’s Energy Efficiency Plan filed with the Texas Commission, the Company expects to spend approximately $6.1 million in costs through 2009 for incentive payments to achieve its energy efficiency goal.
New Mexico Regulatory Matters
NMPRC Case No. 06-00258-UT 2006 Rate Filing. On June 30, 2006, the Company filed a petition with the NMPRC to increase overall rates by approximately $31.7 million. The current rate case filing requests an increase in non-fuel base rates of $13.1 million and an increase of $18.6 million in fuel and purchased power cost recovery. The Company requested that all fuel and purchased power costs be recovered through its Fuel and Purchased Power Cost Recovery Clause (“FPPCAC”). The Company’s requested FPPCAC was based on natural gas costs of $9.50 per MMBtu for the forecast period June 2007 through May 2008. In addition, the Company requested that power provided from Palo Verde Unit 3, which is a deregulated non-utility plant in New Mexico, be priced at the lowest market price for equivalent firm capacity and energy available to the Company. Requested rates would not be effective before July 1, 2007. The NMPRC Staff, the New Mexico Attorney General and the Department of Defense submitted responsive testimony on November 29, 2006 and the Company submitted rebuttal testimony on January 10, 2007. A stipulation (“2007 New Mexico Stipulation”) was filed on February 6, 2007 resolving all issues in the case subject to NMPRC approval. The 2007 New Mexico Stipulation is unopposed and signed by all parties in the proceeding, except the New Mexico Industrial Energy Consumers (“NMIEC”) and the Public Service Company of New Mexico (“PNM”).
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. The 2007 New Mexico Stipulation reflects revised fuel costs for the June 2007 through May 2008 forecast period which reflect average natural gas costs of $7.20 per MMBtu. Most of the Company’s fuel and purchased power costs during the period of the 2007 New Mexico Stipulation will be recovered through base rates with any difference between actual fuel and purchased power costs and the amount included in base rates will be recovered or refunded through the FPPCAC. Rates will continue in effect until changed by the NMPRC after the Company’s 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 July 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 included in base rates and the FPPCAC based upon the cost of capacity and fuel charges 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 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 the New Mexico
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jurisdictional portion of 90% 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 if the SPS purchased power contract is modified or terminated. 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.
A hearing on the 2007 New Mexico Stipulation will be held on March 20, 2007. A final order of the NMPRC is expected no later than July 19, 2007. Management cannot predict whether the NMPRC will approve the 2007 New Mexico Stipulation.
Fuel and Purchased Power Costs. In April 2004, the NMPRC, as part of the 2004 New Mexico Stipulation and Final Order in NMPRC Case No. 03-00302, approved a FPPCAC. The Company currently recovers fuel and purchased power costs in base rates in the amount of $0.01949 per kWh and recovers the remaining fuel and purchased power costs through its FPPCAC. Fuel and purchased power costs associated with 10 percent of the Company’s jurisdictional retail sales in New Mexico are fixed at $0.021 per kWh, and are not reconcilable. See discussion of NMPRC Case No. 06-00258-UT above.
On August 29, 2005, the Company filed the annual reconciliation of its FPPCAC for the period June 1, 2004 through May 31, 2005 in compliance with the requirements of the NMPRC’s Final Order in NMPRC Case No. 03-00302-UT. The Company requested reconciliation of its fuel and purchased power costs for this period, except for the 10 percent portion, and requested recovery of $1.3 million for the New Mexico jurisdictional portion of purchased power capacity costs. The NMPRC Final Order issued April 11, 2006 reconciled the Company’s FPPCAC for the limited purpose of summarizing and verifying all actual revenues and costs, but did not establish the reasonableness of the Company’s fuel and purchased power costs for the reconciliation period. On August 30, 2006, the Company filed the annual reconciliation for its FPPCAC for the period June 1, 2005 through May 31, 2006. As discussed above, the 2007 New Mexico Stipulation provides for final reconciliation of fuel and purchased power costs through December 31, 2005. The Company believes it has fully supported the recovery of all of its applicable fuel and purchased power costs for the period, but cannot predict how the NMPRC will rule on the 2007 New Mexico Stipulation or in a future rate case addressing fuel and purchased power costs after December 31, 2005. An adverse ruling by the NMPRC could have a material negative effect on the Company’s results of operations.
Renewables. The New Mexico Renewable Energy Act of 2004 requires that, by January 1, 2006, renewable energy comprise no less than 5% of the Company’s total retail sales to New Mexico customers. The requirement increases by 1% annually until January 1, 2011, when the renewable portfolio standard shall reach a level of 10% of the Company’s total retail sales to New Mexico customers and will remain fixed at such level thereafter. The Company has met all requirements to date.
Index to Financial Statements EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
On September 1, 2006, the Company filed its annual Procurement Plan detailing its proposed actions to comply with the Renewable Energy Act through 2011.
The NMPRC approved the Company’s 2006 Annual Procurement Plan in December 2006, acknowledging the Company’s existing plan to (i) enter into a contract to purchase renewable energy certificates (“RECs”) for full requirements in 2006 and 2007 and approximately 50% of the Company’s requirements in 2008 through 2011 and (ii) to create a deferral, with carrying costs for future recovery from customers of up to $0.2 million in costs related to the issuance of a diversity RFP for renewable resources and for investigation of small projects to meet the remaining requirements in the 2008 to 2011 timeframe and thereafter. In addition, the Commission authorized the Company to enter into two 20-year purchased power agreements to purchase energy from an 8 megawatt low-emissions biomass generating facility and from a 6 kilowatt solar energy generating facility. Both generating facilities will be located within the Company’s New Mexico service area. Costs incurred by the Company to purchase RECs to meet the requirements of the New Mexico Renewable Energy Act are to be recovered through the FPPCAC as purchased power costs from New Mexico customers pursuant to the Renewable Energy Act and the NMPRC Final Order in NMPRC Case No. 05-00231-UT. The NMPRC’s decision in that case has been appealed to the New Mexico Supreme Court by the New Mexico Industrial Energy Consumers, and oral argument is scheduled for March 12, 2007. The Company is unable to predict how the New Mexico Supreme Court will rule in this proceeding.
Federal Regulatory Matters
Transmission Dispute with Tucson Electric Power. 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 claimed that, under the Transmission Agreement, it was entitled to up to 400 MW of transmission rights on the Company’s 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 Arizona. The Company asserted that TEP’s 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 Company’s 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. TEP’s request for a rehearing of the FERC’s 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; however, the hearing was held in abeyance to allow time for the parties to attempt to negotiate a settlement. The Company and TEP have been unable to reach a settlement, and a hearing before an administrative law judge on the dispute has been scheduled to begin on May 22, 2007. An initial decision of the administrative law judge is expected no later than January 30, 2008. While the Company believes that it is not probable that TEP will prevail, the Company cannot predict the outcome of this case. During 2006 TEP paid the Company $3.5 million for
Index to Financial Statements EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
transmission service relating to the LEF of which the Company has included $3.1 million in its 2006 operating revenues. If the FERC were to rule in TEP’s favor, the Company may be required to refund all of the $3.5 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 Company’s results of operations.
RTOs. FERC’s rule (“Order 2000”) on RTOs strongly encourages, but does not require, public utilities to form and join RTOs. The Company is an active participant in the development of WestConnect, formerly known as the Desert Southwest Transmission and Reliability Operator. A WestConnect Memorandum of Understanding (“MOU”) was signed by the Company and nine other transmission owners on December 6, 2004. On November 21, 2005 an eleventh member joined. This MOU 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 Company’s exports of power to the CFE in Mexico pursuant to a license granted by the DOE and a presidential permit. The DOE has determined that all such exports over international transmission lines shall be made in accordance with Order No. 888, which established the FERC rules for open access.
The DOE is authorized to assess operators of nuclear generating facilities a share of the costs of decommissioning the DOE’s uranium enrichment facilities and for the ultimate costs of disposal of spent nuclear fuel. See Note C for discussion of spent fuel storage and disposal costs.
Nuclear Regulatory Commission. The NRC has jurisdiction over the Company’s licenses for Palo Verde and regulates the operation of nuclear generating stations to protect the health and safety of the public from radiation hazards. The NRC also has the authority to grant license extensions pursuant to the Atomic Energy Act of 1954, as amended.
Index to Financial Statements EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Sales for Resale
The Company provides up to 10 MW of firm capacity, associated energy, and transmission service to the Rio Grande Electric Cooperative pursuant to an ongoing contract which requires a two-year notice to terminate. 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.
Index to Financial Statements EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
C. Utility Plant, Palo Verde and Other Jointly-Owned Utility Plant
The table below presents the balance of each major class of depreciable assets at December 31, 2006 (in thousands):
Amortization of intangible plant (software) is provided on a straight-line basis over the estimated useful life of the asset (ranging from 3 to 10 years). The amortization expense for intangible plant was $2.8 million, $1.9 million and $0.9 million for 2006, 2005 and 2004, respectively. The table below presents the estimated amortization expense for the next five years (in thousands):
The Company owns a 15.8% interest in each of the three nuclear generating units and Common Facilities at Palo Verde, in Wintersburg, Arizona. The Palo Verde Participants include the Company and six other utilities: Arizona Public Service Company (“APS”), Southern California Edison Company (“SCE”), Public Service Company of New Mexico (“PNM”), Southern California Public Power Authority, Salt River Project Agricultural Improvement and Power District (“SRP”) and the Los Angeles Department of Water and Power. The operation of Palo Verde and the relationship among the Palo Verde Participants is governed by the Arizona Nuclear Power Project Participation Agreement (the “ANPP Participation Agreement”). 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.
Pursuant to the ANPP Participation Agreement, the Palo Verde Participants share costs and generating entitlements in the same proportion as their percentage interests in the generating units, and each participant is required to fund its share of fuel, other operations, maintenance and capital costs. The Company’s share of direct expenses in Palo Verde and other jointly-owned utility plants is reflected
Index to Financial Statements EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
in fuel expense, other operations expense, maintenance expense, miscellaneous other deductions, and taxes other than income taxes in the Company’s consolidated statements of operations. The ANPP Participation Agreement provides that if a participant fails to meet its payment obligations, each non-defaulting participant shall pay its proportionate share of the payments owed by the defaulting participant. Because it is impracticable to predict defaulting participants, the Company cannot estimate the maximum potential amount of future payment, if any, which could be required under this provision.
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 licensee’s 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 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. In connection with its finding, the NRC stated that it would use the NRC action matrix to determine the most appropriate response, including any increase in NRC oversight or identification of actions that APS needs to take in response to this performance deficiency, and will notify APS of its determination at a later date. Under the NRC’s action matrix, this finding, coupled with a previous NRC “yellow” finding relating to a 2004 matter involving Palo Verde’s safety injection systems, will place Palo Verde in the “multiple/repetitive degraded cornerstone” column of the NRC’s action matrix which the Company expects will result in an enhanced NRC inspection regimen. This enhanced inspection regimen and any resulting corrective actions could result in increased operating costs at the plant. Of the 103 commercial nuclear reactors in the United States regulated by the NRC, only three reactors were in the “multiple/repetitive degraded cornerstone” category as of the fourth quarter 2006. The Company is currently unable to predict the impact that the NRC’s increased oversight may have on Palo Verde’s operations and the cost of operations.
Other jointly-owned utility plant includes a 7% interest in Units 4 and 5 at Four Corners Generating Station (“Four Corners”) and certain other transmission facilities. A summary of the Company’s investment in jointly-owned utility plant, excluding fuel, at December 31, 2006 and 2005 is as follows (in thousands):
Index to Financial Statements EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Palo Verde
Decommissioning. Pursuant to the ANPP Participation Agreement and federal law, the Company must fund its share of the estimated costs to decommission Palo Verde Units 1, 2 and 3, including the Common Facilities, through the term of their respective operating licenses. Decommissioning costs are estimated every three years based upon engineering cost studies performed by outside engineers retained by APS.
In accordance with the ANPP Participation Agreement, the Company is required to 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 was above its minimum funding level as of December 31, 2006. The Company will continue to monitor the status of its decommissioning funds and adjust its deposits, if necessary, to remain at or above its minimum accumulation requirements in the future.
The Company has established external 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. As of December 31, 2006 and 2005, the fair market value of the trust funds was approximately $114.7 million and $96.0 million, respectively, which is reflected in the Company’s consolidated balance sheets in deferred charges and other assets.
In 2005, the Palo Verde Participants approved the 2004 Palo Verde decommissioning study. Some changes in the cost calculations occurred between the prior 2001 study and the 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. The previous cost estimate from the 2001 study estimated that the Company needed to fund approximately $311.6 million (stated in 2001 dollars). Had an equivalent estimate been calculated for the 2001 study in 2004 dollars, based upon the same 3.6% escalation rate utilized in the 2001 study, the previous estimate would have been $346.5 million. See “Spent Fuel Storage” below.
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. The decommissioning study is updated every three years. The 2007 study is expected to be complete in the second quarter of 2008. See “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
Index to Financial Statements EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
permanent disposal. The 2004 decommissioning study assumed that costs to store fuel on-site will become the responsibility of the DOE after 2037. APS believes that spent fuel storage or disposal methods will be available 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 DOE’s 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 DOE’s acceptance of spent fuel. The Company is unable to predict the outcome of these matters at this time.
Disposal of Low-Level Radioactive Waste. Congress has established requirements for the disposal by each state of low-level radioactive waste generated within its borders. Arizona, California, North Dakota and South Dakota have entered into a compact (the “Southwestern Compact”) for the disposal of low-level radioactive waste. California will act as the first host state of the Southwestern Compact, and Arizona will serve as the second host state. The construction and opening of the California low-level radioactive waste disposal site in Ward Valley has been delayed due to extensive public hearings, disputes over environmental issues and review of technical issues related to the proposed site. Palo Verde is projected to undergo decommissioning during the period in which Arizona will act as host for the Southwestern Compact. The opposition, delays, uncertainty and costs experienced in California demonstrate possible roadblocks that may be encountered when Arizona seeks to open its own waste repository. APS currently believes that interim low-level waste storage methods are or will be available to allow each Palo Verde unit to continue to operate and to store safely low-level waste until a permanent disposal facility is available.
Steam Generators. APS identified accelerated degradation in the steam generator tubes of each unit which required the eventual replacement of the steam generators. New steam generators were installed at Unit 2 during 2003 at a cost to the Company of approximately $45.3 million ($36.4 million in direct costs) and in Unit 1 during 2005 at a cost to the Company of approximately $40.1 million ($36.1 million in direct costs). The steam generators at Unit 3 are scheduled to be replaced in late 2007. The steam generator replacements were based on analysis of the net economic benefit from expected
Index to Financial Statements EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
improved performance of the respective units and the need to realize continued production from the units over their full licensed lives. The eventual total project cash expenditures for steam generator replacements for Units 1, 2 and 3 are currently estimated to be $710.5 million in direct costs (the Company’s portion being $112.3 million). As of December 31, 2006, the Company has paid approximately $87.7 million of such costs. The Company expects its portion will be substantially funded with internally generated cash. See also Part II, Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Overview.”
After the steam generators were replaced at Palo Verde Unit 1 it operated at significantly reduced power levels from December 25, 2005 until March 18, 2006 and did not operate from March 18, 2006 until early July 2006 while repairs and modifications were made to one of its shutdown cooling lines. Palo Verde Unit 1 reached full capacity on July 16, 2006. Palo Verde Unit 1 experienced a 27 day outage in September and October 2006 to replace pressurizer heaters.
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 Company’s 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 $101 million, subject to an annual limit of $15 million per incident. Based upon the Company’s 15.8% interest in the three Palo Verde units, the Company’s maximum potential assessment per incident for all three units is approximately $47.9 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
Index to Financial Statements EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
the accumulated funds for these insurance programs, the Company could be assessed retrospective premium adjustments of up to $9.5 million for the current policy period.
D. Accounting for Asset Retirement Obligations
The Company complies with SFAS No. 143, “Accounting for Asset Retirement Obligations” which primarily affects the accounting for the decommissioning of the Company’s Palo Verde and Four Corners Stations and the method used to report the decommissioning obligation. The Company records the increase in the ARO due to the passage of time as an operating expense (accretion expense). As the DOE assumes responsibility for the permanent disposal of spent fuel, spent fuel costs have not been included in the ARO calculation. The Company has six external trust funds with an independent trustee which are legally restricted to settling its ARO at Palo Verde. The fair value of the funds at December 31, 2006 is $114.7 million.
A reconciliation of the Company’s ARO liability recorded is as follows (in thousands):
(1) Results from the implementation of FIN 47 (see discussion below).
The Company has transmission and distribution lines which are operated under various property easement agreements. If the easements were to be released, the Company may have a legal obligation to remove the lines; however, the Company has assessed the likelihood of this occurring as remote. The majority of these easements include renewal options which the Company routinely exercises.
In 2005, the Palo Verde Participants approved the 2004 Palo Verde decommissioning study. Some changes in the cost calculations occurred between the prior 2001 study and the 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. The previous cost estimate from the 2001 study estimated that the Company needed to fund approximately $311.6 million (stated in 2001 dollars). Had an equivalent estimate been calculated for the 2001 study in 2004 dollars, based upon the same 3.6% escalation rate utilized in the 2001 study, the previous estimate would have been $346.5 million. The ARO liability calculation begins with the cost estimate of $335.7 million from the 2004 study, then
Index to Financial Statements EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
escalates that cost over the remaining life of the plant, and finally discounts the resulting cost at a credit-risk adjusted discount rate. Since the Company assumed an escalation rate of 3.6% and a credit-risk adjusted discount rate of 9.5% in the original calculation of the ARO liability, the ARO liability is less than the Company’s share of the current estimated cost to decommission Palo Verde in 2004 dollars. As Palo Verde approaches the end of its estimated useful life, the difference between the ARO liability and future current cost estimates will narrow over time due to the accretion of the ARO liability.
SFAS No. 143 requires the Company to revise its previously recorded ARO for any changes in estimated cash flows. Any changes that result in an upward revision to estimated cash flows shall be treated as a new liability. Any downward revisions to the estimated cash flows result in a reduction to the previously recorded ARO. Since the 2004 study reflects a downward revision in the estimated cash flows for decommissioning costs from the 2001 study, the Company recorded a $1.8 million reduction to its ARO asset and liability in the third quarter of 2005. Accretion and depreciation expense related to the ARO decreased approximately $0.3 million annually as a result of this adjustment.
Effective December 31, 2005, the Company adopted FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations,” (“FIN 47”). FIN 47 clarifies that the term “conditional” as used in SFAS No. 143, refers to a legal obligation to perform an asset retirement activity even if the timing and/or settlement are conditional on a future event that may or may not be within the control of an entity. Accordingly, the entity must record a liability for the conditional asset retirement obligation if the fair value of the obligation can be reasonably estimated. The adoption of FIN 47 primarily affected the accounting for the disposal obligations of the Company’s fuel oil storage tanks, water wells, evaporative ponds and asbestos found at the Company’s gas-fired generating plants. With the adoption of FIN 47 at December 31, 2005, the Company recognized an increase in its ARO of $2.7 million, an increase in net plant in service of $0.9 million, and a cumulative effect of accounting change resulting in a loss of $1.1 million, net of related taxes. As of December 31, 2004, proforma ARO liability related to FIN 47 would have been $2.6 million.
Amounts recorded under SFAS No. 143, including those under FIN 47, are subject to various assumptions and determinations such as (i) whether a legal obligation exists to remove assets; (ii) estimation of the fair value of the costs of removal; (iii) when final removal will occur; (iv) future changes in decommissioning cost escalation rates; and (v) the credit-adjusted interest rates to be utilized in discounting future liabilities. Changes that may arise over time with regard to these assumptions and determinations will change amounts recorded in the future as an expense for AROs. If the Company incurs or assumes any liability in retiring any asset at the end of its useful life without a legal obligation to do so, it will record such retirement costs as incurred.
Index to Financial Statements EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
E. Common Stock
Overview
The Company’s common stock has a stated value of $1 per share, with no cumulative voting rights or preemptive rights. Holders of the common stock have the right to elect the Company’s directors and to vote on other matters.
Long-Term Incentive Plans
The Company’s shareholders have approved the adoption of two stock-based long-term incentive plans. The first plan was approved in 1996 (the “1996 Plan”) and authorized the issuance of up to 3.5 million shares of common stock for the benefit of officers, key employees and directors. The second plan was approved in 1999 (the “1999 Plan”) and authorized the issuance of up to two million shares of common stock for the benefit of directors, officers, managers, other employees and consultants. Under the plans, common stock may be issued through the award or grant of non-statutory stock options, incentive stock options, stock appreciation rights, restricted stock, bonus stock and performance stock. As of December 31, 2006, there were 173,065 shares available for future awards under these two plans. The Company may issue new shares, purchase shares on the open market, or issue shares from shares the Company has repurchased to meet the share requirements of these plans.
As discussed in Note A, the Company adopted SFAS No. 123 (revised) effective January 1, 2006. The Company adopted the “modified prospective application method” as provided for in SFAS No. 123 (revised) which provides for compensation expense related to unvested stock awards to be recognized prospectively. Under the modified prospective application method, compensation expense for unvested awards is recognized over the remaining service periods of those awards and the cumulative change in compensation expense vested in prior periods is recognized in the period the new accounting standard is adopted.
Stock Options. Stock options have been granted at exercise prices equal to or greater than the market value of the underlying shares at the date of grant. The fair value for these options was estimated at the grant date using the Black-Scholes option pricing model. The options expire ten years from the date of grant unless terminated earlier by the Board of Directors. No stock options were granted during 2006 or 2005.
Index to Financial Statements EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following table summarizes the transactions in the Company’s stock options for 2006:
The Company received approximately $3.1 million in cash for the 396,560 stock options exercised in 2006. During 2006, the Company realized $0.9 million in current tax benefits, at the alternative minimum tax rate, from the exercise of stock options. No current tax benefits were realized for the tax deduction from stock options exercised in 2005 and 2004 because the Company was in a tax net operating loss position. The intrinsic value of stock options exercised in 2006, 2005 and 2004 was $5.6 million, $7.8 million and $0.5 million, respectively. The fair value at grant date of options vested during 2006, 2005 and 2004 was $1.2 million, $1.5 million and $1.6 million, respectively. No options were forfeited or expired during 2006.
The Company recorded compensation cost of $0.8 million in 2006, related to the 140,000 outstanding unvested stock option awards and the tax benefit and capitalized costs related to these compensation costs were less than $0.3 million. On January 2, 2007, 120,000 stock options vested for which compensation expense was recognized by December 31, 2006. The unvested stock option awards have remaining $0.1 million of unrecognized compensation cost. That cost is expected to be recognized in 2007. The weighted average aggregate fair value at grant date of these unvested stock options is $0.9 million. Weighted average assumptions and grant-date fair value for options granted in 2004 are presented below:
Index to Financial Statements EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Restricted Stock. The Company has awarded restricted stock under its long-term incentive plans. Restrictions from resale generally lapse and awards vest over periods of one to five years. The market value of vested restricted stock awards is expensed at the time of grant. The market value of the unvested restricted stock at the date of grant is included in Capital in Excess of Stated Value in Common Stock Equity and is amortized to expense over the restriction period. Approximately $1.6 million, $1.4 million and $1.2 million was charged to expense related to restricted stock awards in 2006, 2005 and 2004, respectively. The deferred tax benefit related to these expenses was $0.6 million, $0.6 million and $0.5 million for 2006, 2005 and 2004, respectively. The Company realized $0.4 million of current tax benefits, at the alternative minimum tax rate, from the issuance of restricted stock in 2006. No current tax benefits were realized for the tax deduction from restricted stock issuances in 2005 and 2004 because the Company was in a tax net operating loss position. Any capitalized costs related to these expenses would be less than $0.1 million for all years. The aggregate intrinsic value for restricted stock vested during 2006, 2005 and 2004 was $1.9 million, $1.5 million and $1.4 million, respectively. The fair value at grant date for restricted stock vested in 2006, 2005 and 2004 was $1.6 million, $1.1 million and $1.1 million, respectively. The outstanding restricted stock has remaining $0.8 million of unrecognized expense at December 31, 2006 that is expected to be recognized over the weighted average remaining contractual term of the outstanding restricted stock of approximately one year. The aggregate intrinsic value of the 110,854 outstanding restricted shares at December 31, 2006 was $2.7 million.
The following table summarizes the unvested restricted stock transactions for 2006:
The weighted average fair values at grant date for restricted stock awarded during 2006, 2005 and 2004 are $19.85, $18.82 and $14.40, respectively.
The holder of a restricted stock award has rights as a shareholder of the Company, including the right to vote and, if applicable, receive cash dividends on restricted stock, except that certain restricted stock awards require any cash dividend on restricted stock to be delivered to the Company in exchange for additional shares of restricted stock of equivalent market value.
Performance Shares. The Company has granted performance share awards to certain officers under the Company’s existing long-term incentive plans, which provide for issuance of Company stock based on the achievement of certain performance criteria over a three-year period. The payout varies
Index to Financial Statements EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
between 0% to 200% of performance shares. On January 1, 2006, 68,425 performance shares were issued at the 175% performance level with a total cost of $1.4 million which had been expensed ratably over 2004 and 2005. The Company realized $0.3 million of current tax benefits at the alternative minimum tax rate from the issuance of performance shares in 2006. The requisite service period for these shares ended December 31, 2005, and the shares had an aggregate intrinsic value of $1.4 million. On January 1, 2007, 2008 and 2009, subject to meeting certain performance criteria, additional performance shares will be issued. In accordance with SFAS No. 123 (revised), the Company will recognize the related compensation expense by ratably amortizing the grant date fair market value of awards over the requisite service period and the compensation expense will only be adjusted for forfeitures. The actual number of shares issued can range from zero to 348,200 shares.
The fair market value at the date of grant for the three separate grants of performance shares was based upon a Monte Carlo simulation. The Monte Carlo simulation reflected the structure of the performance plan which calculates the share payout on performance of the Company relative to a defined peer group over a three-year performance period based upon total return to shareholders. The fair market value was determined as the average payout of one million simulation paths discounted to the grant date using a risk-free interest rate based upon the constant maturity treasury rate yield curve at the grant date. The expected volatility of total return to shareholders is calculated in accordance with the plan’s term structure and includes the volatilities of all members of the defined peer group.
The following table summarizes the outstanding performance share awards at the 100% performance level:
The outstanding performance awards have remaining $1.2 million of unrecognized expense at December 31, 2006 that is expected to be recognized over the weighted average remaining contractual term of the awards of approximately 1.2 years. The aggregate intrinsic value of the 174,100 outstanding awards (based on 100% performance level) at December 31, 2006 was $4.2 million. The weighted average grant date fair value of performance shares awarded during the years 2006, 2005 and 2004 was $18.37, $22.55 and $18.39, respectively. The fair value of performance shares which vested in 2006 was $0.8 million with an intrinsic value of $0.8 million. There were no performance shares which vested in 2005 and 2004.
Index to Financial Statements EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
During the first quarter of 2006, the Company recorded a cumulative adjustment to operating expense related to 2004 and 2005 performance stock awards to reflect the implementation of SFAS No. 123 (revised) which reduced expense by $0.7 million pretax, $0.4 million after-tax. For 2006, the Company recorded $0.4 million of compensation expense for the performance share awards which included the cumulative adjustment.
Prior to implementing SFAS No. 123 (revised) the Company recognized compensation expense for performance share awards by ratably amortizing their fair market value at the end of the reporting period based on the Company’s performance at that time over the performance cycles. The Company recorded compensation expense related to performance share awards of $1.5 million and $1.6 million for 2005 and 2004, respectively. The deferred tax related to these expenses was $0.6 million for 2005 and 2004.
Common Stock Repurchase Program
In September 2006, the Board of Directors (the “Board”) authorized the repurchase of up to 2.3 million shares of the Company’s outstanding common stock (the “2006 Plan”). The shares authorized under the 2006 Plan are in addition to the shares which were available under a buy back program previously approved by the Board in February 2004 (the “2004 Plan”). No common stock was repurchased during 2005. During 2006, the Company repurchased 2,660,820 shares of common stock at an aggregate cost of $62.4 million. As of December 31, 2006, no shares remain available under the 2004 Plan, and approximately 1.3 million shares remain authorized to be repurchased under the 2006 Plan. The Company may in the future make purchases of its stock pursuant to its stock repurchase plan at open market prices and may engage in private transactions, where appropriate. The repurchased shares will be available for issuance under employee benefit and stock option plans, or may be retired.
Index to Financial Statements EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Reconciliation of Basic and Diluted Earnings Per Share
The reconciliation of basic and diluted earnings per share before cumulative effect of accounting change and extraordinary item is presented below:
Index to Financial Statements EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Options excluded from the computation of diluted earnings per share because the exercise price was greater than the average market price for the periods presented are as follows:
Index to Financial Statements EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
F. Accumulated Other Comprehensive Income (Loss)
Accumulated other comprehensive income (loss) consists of the following components (in thousands):
Index to Financial Statements EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
G. Long-Term Debt and Financing Obligations
Outstanding long-term debt and financing obligations are as follows:
(1) Pollution Control Bonds
The Company has four series of tax exempt Pollution Control Bonds in an aggregate principal amount of approximately $193.1 million. Upon the occurrence of certain events which includes the remarketing of the bonds, the bonds may be required to be repurchased at the holder’s option or are subject to mandatory redemption. On August 1, 2005, the Company reissued three series of pollution control bonds in the amounts of $63.5 million, $59.2 million and $37.1 million. The $59.2 million bonds which mature in 2040, were reissued with a fixed interest rate of 4.80% and an effective interest rate of 5.27% after considering related insurance and issuance costs. The $63.5 million and $37.1 million bonds, which also mature in 2040, were reissued with a variable rate that is repriced weekly, 3.85% at December 31, 2006. The Company also remarketed $33.3 million of pollution control bonds which bear a fixed interest rate of 4% until August 1, 2012 which is the date the bonds are due to be remarketed. The effective interest rate for these bonds is 4.70% after considering related insurance and issuance costs. The interest rate will remain at its current fixed interest rate until remarketing in August 2012. The reissuance and remarketing replaced four series of bonds which were subject to mandatory tender or remarketing as of August 1, 2005.
Index to Financial Statements EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(2) Senior Notes
The Company filed a shelf registration statement on Form S-3 with the Securities and Exchange Commission which became effective in May 2005. The shelf registration statement enables the Company to offer and issue debt securities, first mortgage bonds, shares of stock and certain other securities from time to time in one or more offerings of up to $1.0 billion.
In May 2005, the Company issued $400.0 million aggregate principal amount of its 6% Senior Notes due May 15, 2035 (the “Notes”) under its shelf registration statement. The proceeds from the issuance of the Notes of $397.7 million (net of a $2.3 million discount) were used to fund the retirement of the Company’s first mortgage bonds.
(3) Nuclear Fuel and Working Capital Financing
The Company has available a $150 million credit facility that was renewed in 2006 for a five-year term ending April 2011. During the term of the agreement, the credit facility may be increased to $200 million. The credit facility provides for up to $70 million for the financing of nuclear fuel, which is accomplished through a trust that borrows under the facility to acquire and process the nuclear fuel. The Company is obligated to repay the trust’s borrowings with interest. In the Company’s financial statements, the assets and liabilities of the trust are reported as assets and liabilities of the Company. Any amounts not borrowed by the trust may be borrowed by the Company for working capital needs. The weighted average interest rate on the credit facility was 5.9% as of December 31, 2006.
The $150 million credit facility requires compliance with certain total debt and interest coverage ratios. The Company was in compliance with these requirements throughout 2006. No amounts are currently outstanding on this facility for working capital needs.
Excluding future obligations and maturities related to nuclear fuel purchase commitments, the Company has no scheduled maturities of long-term debt and financing obligations for the next five years as of December 31, 2006.
Index to Financial Statements EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
H. Income Taxes
The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and liabilities at December 31, 2006 and 2005 are presented below (in thousands):
Based on the average annual book income before taxes for the prior three years, excluding the effects of extraordinary and unusual or infrequent items, the Company believes that the net deferred tax assets will be fully realized at current levels of book and taxable income.
Index to Financial Statements EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The Company recognized income taxes as follows (in thousands):
The current federal income tax expense for 2006 results primarily from the accrual of alternative minimum tax (“AMT”). The current income tax expense for 2005 results primarily from a reversal of AMT for prior years as a result of increased tax deductions due to several method changes primarily related to tax depreciation and repair allowances. The current income tax expense for 2004 results primarily from the accrual of AMT. Deferred federal income tax includes an offsetting AMT expense of $8.4 million and $6.7 million for 2006 and 2005, respectively, and an offsetting benefit of $18.9 million for 2004. The reduction in deferred state income taxes is a result of legislation 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. The Company’s 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 will result 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, the Company recorded a $6.2 million reduction in its 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 includes: (i) a
Index to Financial Statements EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 state income tax benefit for 2004 results primarily from the state effects of the re-application of SFAS No. 71 to the Company’s New Mexico jurisdictional operations and an IRS settlement in 2004.
Income tax provisions differ from amounts computed by applying the statutory federal income tax rate of 35% to book income before federal income tax as follows (in thousands):
The effective tax rate in 2006 excluding the adjustment to deferred income taxes for the change in Texas franchise (income) tax law of $6.2 million was 36.8%. The effective income tax rate in 2004 excluding the tax benefit associated with the reduction in estimated contingent tax liability of $3.5 million and state taxes net of federal benefit of $2.7 million was 36.2%. See Note I.
As of December 31, 2006, the Company had $50.2 million of AMT credit carryforwards that have an unlimited life.
Index to Financial Statements EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
I. Commitments, Contingencies and Uncertainties
Power Contracts
As of December 31, 2006, the Company had entered into the following significant agreements with various counterparties for forward firm purchases and sales of electricity:
In addition to the above transactions, the Company has also entered into several agreements with various counterparties for the forward firm purchases and sales of electricity during the first quarter of 2007:
Environmental Matters
The Company is subject to regulation with respect to air, soil and water quality, solid waste disposal and other environmental matters by federal, state, tribal and local authorities. Those authorities govern current facility operations and have continuing jurisdiction over facility modifications. Failure to comply with these environmental regulatory requirements can result in actions by regulatory agencies or other authorities that might seek to impose on the Company administrative, civil, and/or criminal penalties. If the United States regulates green house gas emissions, the Company’s fossil fuel generation assets will be faced with the additional cost of monitoring, controlling and reporting these emissions. A significant portion of the Company’s generation assets are nuclear and gas fired. As a result, the Company does not believe such regulations would impose greater burdens on the Company than on most other electric utilities. 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. Environmental regulations can change rapidly and are often difficult to predict. While the Company strives to prepare for and implement changes necessary to comply with changing environmental regulations, substantial expenditures may be required for the Company to comply with such regulations in the future.
Index to Financial Statements EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 $2.0 million as of December 31, 2006, which is related to compliance with federal and state environmental standards. However, unforeseen expenses associated with compliance could have a material adverse effect on the future operations and financial condition of the Company.
The Company incurred the following expenditures to comply with federal environmental statutes (in thousands):
(1) Includes $1.1 million and $0.6 million in remediation costs for the twelve months ended December 31, 2005 and 2004, respectively.
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 Company’s position is that any liability it may have related to the SESCO site was discharged in the Company’s bankruptcy. At this time, the Company has not agreed to the 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.
In the first quarter of 2006, a fuel oil release was discovered at one of the Company’s local generating plants. The fuel oil from an above ground storage tank spilled due to a pipeline malfunction and was contained inside a safety corridor. It is estimated that approximately 95% of fuel oil released was recovered and placed back into the fuel inventory. During the second quarter of 2006, the Company completed its assessment of the situation and started the remediation process on the contaminated soil containing the remaining 5% of the fuel oil. The estimated cost to address this incident is $0.8 million which has been recorded as maintenance expense in the Company’s financial statements.
Index to Financial Statements EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
On September 26, 2006, the Secretary of the New Mexico Environment Department issued a Compliance Order concerning the Company’s Rio Grande Generating Station, located in Doña 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 no penalties have been incurred.
Except as described herein, the Company is not aware of any other active investigation of its compliance with environmental requirements by the Environmental Protection Agency, the TCEQ or the New Mexico Environment Department which is expected to result in any material liability. Furthermore, except as described herein, the Company is not aware of any unresolved, potentially material liability it would face pursuant to the Comprehensive Environmental Response, Comprehensive Liability Act of 1980, also known as the Superfund law.
Tax Matters
The Company’s federal income tax returns for the years 1999 through 2002 have been examined by the IRS. On May 9, 2005, the Company received an IRS notice of proposed deficiency. The primary audit adjustments proposed by the IRS related to (i) whether the Company was 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 the Company was 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. The proposed IRS adjustments would affect the timing of these deductions not their ultimate deductibility for federal income tax purposes. The Company has protested the audit adjustments through administrative appeals and believes that its treatment of the payments is supported by substantial legal authority. In the event that the IRS prevails, the resulting income tax and interest payments could be material to the Company’s cash flows. The IRS is currently performing an examination of the 2003 and 2004 income tax returns.
The Company has established, and periodically reviews and re-evaluates, an estimated contingent tax liability on its consolidated balance sheet to provide for the possibility of adverse outcomes in tax proceedings. Although the ultimate outcome of the ongoing examinations cannot be predicted with certainty, and while the contingent tax liability may not in fact be sufficient, the Company believes that the amount of contingent tax liability recorded as of December 31, 2006 is a reasonable estimate of any additional tax that may be due.
Index to Financial Statements EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
MiraSol Warranty Obligations
MiraSol is an energy services subsidiary which offered a variety of services to reduce energy use and/or lower energy costs. MiraSol was not a power marketer. On July 19, 2002, all sales activities of MiraSol ceased. MiraSol remains a going concern in order to satisfy current contracts and warranty and service obligations on previously installed projects. Based on an analysis performed by the Company, an additional $0.5 million in potential warranty claims were identified and expensed during 2006. As of December 31, 2006, the Company has a reserve for warranty claims in the amount of approximately $1.8 million. Accruals, charges and balances for the reserve for warranty claims are as follows:
While no other probable warranty liabilities have been identified at this time, if it is determined at a future date that MiraSol has further obligations to any customer, and contributions from MiraSol, its subcontractors or any other third party are insufficient to honor the warranty obligations, the Company intends to honor any such warranty obligations after making appropriate regulatory filings, if any.
Lease Agreements
The Company has operating leases for administrative offices and certain warehouse facilities. The administrative offices lease expires on May 31, 2007. The minimum lease payments for 2007, through the term of the lease, are $0.4 million. The warehouse facilities lease expires in December 2009 and has three concurrent renewal options of one year each. The lease payments are $0.3 million annually. The lease agreements do not impose any restrictions relating to issuance of additional debt, payment of dividends or entering into other lease arrangements. The Company has no significant capital lease agreements.
The Company’s total annual rental expense related to operating leases was $1.7 million, $1.1 million and $1.2 million for 2006, 2005 and 2004, respectively. As of December 31, 2006, the Company’s minimum future rental payments for the next five years are as follows (in thousands):
Index to Financial Statements EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Union Matters
The Company has historically had a union workforce of approximately 300 employees. In 2003 and 2004, 136 additional employees, from the meter reading, collections, facilities services, and customer service areas, voted to join the union. The union contract for the historical group of 300 union employees expired on June 30, 2006, and currently all 436 union employees are working without a contract. The Company has been engaged in negotiations with the union on a new collective bargaining agreement for all the union employees since May 2006. The Company has accrued approximately $0.3 million for retroactive pay increases for the historical group of 300 union employees for the third and fourth quarters of 2006.
J. Litigation
The Company is a party to various legal actions. In many of these matters, the Company has excess casualty liability insurance that covers the various claims, actions and complaints. Based upon a review of these claims and applicable insurance coverage, 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 May 21, 2003, the Company was served with a complaint by the Port of Seattle seeking civil damages under the Sherman Act, the Racketeer Influenced and Corrupt Organization Act, and state antitrust laws, as well as for fraud (Port of Seattle v. Avista Corporation, et al., No. CV03-117OP). The complaint was filed in the United States District Court for the Western District of Washington. The complaint alleges that the Company, indirectly through its dealings with Enron, conspired with the other named defendants to manipulate the California energy market, which had the effect of artificially inflating the price that the Port of Seattle paid for electricity. The Company, together with several other defendants, filed a motion to dismiss. On May 12, 2004, the Court granted the Company’s motion, and the suit was dismissed. The Port of Seattle filed an appeal of the Court’s decision with the U. S. Court of Appeals for the Ninth Circuit. On March 30, 2006, the Court of Appeals upheld the dismissal of this matter. No further appeal was filed and the dismissal is final.
On May 5, 2004, Wah Chang, a specialty metals manufacturer which operates a plant in Oregon, filed suit against the Company and other defendants in the United States District Court for the District of Oregon. (Wah Chang v. Avista Corporation, et al., No. 04-619AS). The complaint makes substantially the same allegations as were made in Port of Seattle and seeks the same types of damages. In addition, on June 7, 2004, the City of Tacoma filed suit against the Company and other defendants in the United States District Court for the Western District of Washington (City of Tacoma v. American Electric Power Service Corp., et al., C04-5325RBL). This complaint also makes substantially the same allegations as were made in Port of Seattle and seeks civil damages (including treble damages) from the Company and the other defendants for violations of certain antitrust provisions under the Sherman Act. Both of these matters were transferred to the same court that heard and dismissed the Port of Seattle lawsuit and on February 11, 2005, the Court granted the Company’s motion to dismiss both cases.
Index to Financial Statements EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Wah Chang and the City of Tacoma have both filed notices of appeal with the U.S. Court of Appeals for the Ninth Circuit. The parties have filed briefs in both cases and oral arguments are scheduled for April 10, 2007. While the Company believes that these matters are without merit and intends to defend itself vigorously, the Company is unable to predict the outcome or range of possible loss.
See Note B for discussion of the effects of government legislation and regulation on the Company.
Index to Financial Statements EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
K. Employee Benefits
Retirement Plans
The Company’s Retirement Income Plan (the “Retirement Plan”) covers employees who have completed one year of service with the Company and work at least a minimum number of hours each year. The Retirement Plan is a qualified noncontributory defined benefit plan. Upon retirement or death of a vested plan participant, assets of the Retirement Plan are used to pay benefit obligations under the Retirement Plan. Contributions from the Company are at least the minimum funding amounts required by the IRS under provisions of the Retirement Plan, as actuarially calculated. The assets of the Retirement Plan are invested in equity securities, debt securities and cash equivalents and are managed by professional investment managers appointed by the Company.
The Company has two non-qualified retirement income plans that are non-funded defined benefit plans. One plan covers certain former employees of the Company, and the other plan, an excess benefit plan adopted during 2004, covers certain active and former employees of the Company. The benefit cost for the non-qualified retirement income plans are based on substantially the same actuarial methods and economic assumptions as those used for the Retirement Plan.
The obligations and funded status of the plans are presented below (in thousands):
Index to Financial Statements EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Amounts recognized in the Company’s consolidated balance sheets consist of the following (in thousands):
The accumulated benefit obligation for all retirement plans was $172.7 million and $169.4 million at December 31, 2006 and 2005, respectively. The accumulated benefit obligation in excess of plan assets is as follows (in thousands):
On December 31, 2006, the Company adopted SFAS No. 158 “Employer’s Accounting for Defined Benefit Pension and Other Postretirement Plans”, which amended SFAS No. 87 and SFAS No. 132R. The Company uses a measurement date of December 31 for its retirement plans; therefore, there were no adjustments related to a change in measurement date as a result of the adoption of SFAS No. 158. For the incremental effects of applying SFAS No. 158 refer to page 114.
Index to Financial Statements EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Amounts recognized in accumulated comprehensive income that have not been recognized as a component of net periodic benefit cost in accordance with SFAS No. 158 consist of the following at December 31, 2006 (in thousands):
The following are the weighted-average actuarial assumptions used to determine the benefit obligations:
The components of net periodic benefit cost are presented below (in thousands):
Index to Financial Statements EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The changes in benefit obligations recognized in other comprehensive income are presented below (in thousands):
The total amount recognized in net periodic benefit costs and other comprehensive income are presented below (in thousands):
The following are amounts in accumulated other comprehensive income that are expected to be recognized as components of net periodic benefit cost during 2007 (in thousands):
Index to Financial Statements EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following are the weighted-average actuarial assumptions used to determine the net periodic benefit cost at December 31:
The Company reassesses various actuarial assumptions at least on an annual basis. The discount rate is changed at each measurement date based on prevailing market interest rates inherent in high-quality (AA and better) corporate bonds that would provide the future cash flow needed to pay the benefits included in the benefit obligation as they become due, as well as on publicly available bond indices. The Company changed its discount rate to determine the benefit obligations for the retirement income plan and the Excess Benefit Plan from 5.50% to 5.90% and the non-qualified retirement income plan from 5.50% to 5.70% at December 31, 2006. For determining 2007 benefit costs, the 5.90% and the 5.70% discount rates are not expected to change. A 1.0% decrease in the discount rate would increase the 2006 retirement plans’ projected benefit obligation by 15%. A 1.0% increase in the discount rate would decrease the 2006 retirement plans’ projected benefit obligation by 12%.
The Company’s overall expected long-term rate of return on assets is 8.50%, which is both a pre-tax and after-tax rate as pension funds are generally not subject to income tax. The expected long-term rate of return is based on the weighted average of the expected returns on investments based upon the target asset allocation of the pension fund. The Retirement Plan fund includes a diversified portfolio of mutual funds investing in equity securities including large and small capital funds, international funds, and an energy industry specific fund. In addition, the Retirement Plan fund includes mutual funds that invest in commodities and emerging market debt. The Retirement Plan fund also invests in fixed income securities. The target long-term asset allocation provides for investments in real estate. The expected returns for mutual fund investments are based on historical risk premiums above the current fixed income rate, while the expected returns for the fixed income securities are based on the portfolio’s yield to maturity.
Index to Financial Statements EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The Company’s Retirement Plan fund actual and target long-term asset allocations are as follows:
The Company adheres to the traditional capital market pricing theory which maintains that over the long term, the risk of owning equities should be rewarded with a greater return than available from fixed income investments. The Company seeks to minimize the risk of owning equity securities by investing in mutual funds that pursue risk minimization strategies and by diversifying its investments to limit its risks during falling markets. The investment managers have full discretionary authority to direct the investment of plan assets held in trust within the guidelines prescribed by the Company through the plan’s investment policy statement including the ability to hold cash equivalents. The investment guidelines of the investment policy statement are in accordance with the Employee Retirement Income Security Act of 1974 (ERISA) and Department of Labor (DOL) regulations.
The contributions for the Retirement Plan, as actuarially calculated, are at least the minimum funding amounts required by the IRS. The Company expects to contribute $13.6 million to its retirement plans in 2007, although the Company has no 2007 minimum funding requirements for the Retirement Plan.
Index to Financial Statements EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid (in thousands):
Other Postretirement Benefits
The Company provides certain health care benefits for retired employees and their eligible dependents and life insurance benefits for retired employees only. Substantially all of the Company’s employees may become eligible for those benefits if they retire while working for the Company. Contributions from the Company are based on the funding amounts established in the Texas Rate Stipulation. The assets of the plan are invested in equity securities, debt securities, and cash equivalents and are managed by professional investment managers appointed by the Company.
The Company determined that the prescription drug benefits of its plan were actuarially equivalent to the Medicare Part D benefit provided for in the Medicare Prescription Drug, Improvement, and Modernization Act of 2003. FASB Staff Position No. 106-2 “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003” requires measurement of the postretirement benefit obligation, the plan assets, and the net periodic postretirement benefit cost to reflect the effects of the subsidy.
Index to Financial Statements EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following table contains a reconciliation of the change in the benefit obligation, the fair value of plan assets, and the funded status of the plans (in thousands):
Amounts recognized in the Company’s consolidated balance sheets as a non-current liability consist of accrued postretirement costs of $85.4 million and $105.1 million for 2006 and 2005, respectively.
On December 31, 2006, the Company adopted SFAS No. 158 “Employer’s Accounting for Defined Benefit Pension and Other Postretirement Plans”, which amended SFAS No. 106 and SFAS No. 132R. The Company uses a measurement date of December 31 for its other postretirement benefits plan, therefore there were no adjustments related to a change in measurement date as a result of the adoption of SFAS No. 158.
Index to Financial Statements EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following table represents the incremental effects related to the Retirement Plans and Other Postretirement Benefits of applying SFAS No. 158 on certain Balance Sheet line items (in thousands):
Amounts recognized in accumulated comprehensive income that have not been recognized as a component of net periodic cost in accordance with SFAS No. 158 consist of the following for the year ended December 31 (in thousands):
Index to Financial Statements EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following are the weighted-average actuarial assumptions used to determine the accrued postretirement costs:
Net periodic benefit cost is made up of the components listed below (in thousands):
The changes in benefit obligations resulted in a decrease in other comprehensive income of $22.2 million at December 31, 2006 due to the adoption of SFAS No. 158. There were no changes in other comprehensive income due to changes in the benefit obligations for 2005 and 2004.
The total recognized in net periodic benefit cost and other comprehensive income are presented below (in thousands):
The amount of prior service benefit in accumulated other comprehensive income expected to be recognized as a component of periodic benefit cost during 2007 is $2.9 million.
Index to Financial Statements EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following are the weighted-average actuarial assumptions used to determine the net periodic benefit cost:
The Company reassesses various actuarial assumptions at least on an annual basis. The discount rate is evaluated at each measurement date based on prevailing market interest rates inherent in high-quality (AA and better) corporate bonds that would provide the future cash flow needed to pay the benefits included in the benefit obligation as they become due, as well as on publicly available bond indices. At December 31, 2006, the Company changed its discount rate from 5.50% to 5.90% for the other postretirement benefits plan. For determining 2007 benefit cost, the 5.90% discount rate is not expected to change. A 1.0% decrease in the discount rate would increase the 2006 accumulated postretirement benefit obligation by 17.1%. A 1.0% increase in the discount rate would decrease the 2006 accumulated postretirement benefit obligation by 13.5%.
For measurement purposes, a 9.6% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2007; the rate was assumed to decrease gradually to 6% for 2010 and remain at that level thereafter. Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plan. The effect of a 1% change in these assumed health care cost trend rates would increase or decrease the benefit obligation by $19.0 million or $15.3 million, respectively. In addition, such a 1% change would increase or decrease the aggregate service and interest cost components of the net periodic benefit cost by $2.1 million or $1.6 million, respectively.
Index to Financial Statements EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The Company’s overall expected long-term rate of return on assets, on an after-tax basis, is 5.90%. The expected long-term rate of return is based on the after-tax weighted average of the expected returns on investments based upon the target asset allocation. The asset portfolio includes a diversified mix of mutual funds investing in equity securities including large and small capital funds, international funds, and an energy industry specific fund. In addition, the asset portfolio includes mutual funds that invest in commodities and emerging market debt. The asset portfolio also includes fixed income securities and cash equivalents. The target long-term asset allocation provides for investments in real estate. The expected returns for mutual fund investments are based on historical risk premiums above the current fixed income rate, while the expected returns for the fixed income securities are based on the portfolio’s yield to maturity. The Company’s asset portfolio actual and target long-term asset allocations are as follows:
The Company adheres to the traditional capital market pricing theory which maintains that over the long term, the risk of owning equities should be rewarded with a greater return than available from fixed income investments. The Company seeks to minimize the risk of owning equity securities by investing in mutual funds that pursue risk minimization strategies and by diversifying its investments to limit its risks during falling markets. The investment managers have full discretionary authority to direct the investment of plan assets held in trust within the guidelines prescribed by the Company through the plan’s investment policy statement including the ability to hold cash equivalents. The investment guidelines of the investment policy statement are in accordance with the ERISA and DOL regulations.
The Company expects to contribute $3.4 million to its other postretirement benefits plan in 2007.
Index to Financial Statements EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid (in thousands):
401(k) Defined Contribution Plans
The Company sponsors 401(k) defined contribution plans covering substantially all employees. Historically, the Company has provided a 50 percent matching contribution up to 6 percent of the employee’s compensation subject to certain other limits and exclusions. Total matching contributions made to the savings plans for the years 2006, 2005 and 2004 were $1.5 million, $1.5 million and $1.3 million, respectively.
Annual Short-Term Bonus Plan
The Annual Short-Term Bonus Plan (the “Bonus Plan”) provides for the payment of cash awards to eligible Company employees, including each of its named executive officers. Payment of awards is based on the achievement of performance measures reviewed and approved by the Company’s Board of Directors Compensation Committee. Generally, these performance measures are based on meeting certain financial, operational and individual performance criteria. The financial performance goals are based on earnings per share and the operational performance goals are based on safety and customer satisfaction. If a certain level of earnings per share is not attained, no bonuses will be paid under the Bonus Plan. The Company was able to attain the required levels of improvements in the earnings per share, customer satisfaction, and safety goals for low risk employees to pay a $4.8 million bonus for 2006. In 2005, the Company was able to attain the required levels of improvements in the earnings per share and the safety goals for low risk employees which resulted in a bonus of $2.5 million. In 2004 the Company was able to attain the required levels of improvement in earnings per share and the customer satisfaction goals which resulted in a bonus of $3.5 million. The Company was also able to attain the required levels of improvement in the safety performance measures for medium and high risk employees in 2006, 2005 and 2004, which resulted in safety bonuses of $1.3 million, $1.0 million, and $0.9 million, respectively. The Company has renewed the Bonus Plan in 2007 with similar goals.
Index to Financial Statements EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
L. Franchises and Significant Customers
City of El Paso Franchise
The Company has a franchise agreement with the City of El Paso, the largest city it serves, through July 31, 2030. The franchise agreement includes a 3.25% annual franchise fee and allows the Company to utilize public rights-of-way necessary to serve its retail customers within the City.
Las Cruces Franchise
In February 2000, the Company and Las Cruces entered into a seven-year franchise agreement with a 2% annual franchise fee (approximately $1.4 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 by waiving its option to purchase the Company’s distribution system pursuant to the terms of a February 2000 settlement agreement.
Military Installations
The Company currently serves Holloman Air Force Base (“Holloman”), White Sands Missile Range (“White Sands”) and the United States Army Air Defense Center at Fort Bliss (“Ft. Bliss”). The Company’s sales to the military bases represent approximately 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 new contract, subject to regulatory approval, 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.
Index to Financial Statements EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
M. Financial Instruments and Investments
SFAS No. 107, “Disclosure about Fair Value of Financial Instruments,” requires the Company to disclose estimated fair values for its financial instruments. The Company has determined that cash and temporary investments, accounts receivable, decommissioning trust funds, long-term debt and financing obligations, accounts payable and customer deposits meet the definition of financial instruments. The carrying amounts of cash and temporary investments, accounts receivable, accounts payable and customer deposits approximate fair value because of the short maturity of these items. Decommissioning trust funds are carried at market value.
The fair values of the Company’s long-term debt and financing obligations, including the current portion thereof, are based on estimated market prices for similar issues and are presented below (in thousands):
(1) The interest rate on the Company’s financing for nuclear fuel purchases is reset every quarter to reflect current market rates. Consequently, the carrying value approximates fair value.
Treasury Rate Locks. During the first quarter of 2005, the Company entered into treasury rate lock agreements to hedge against potential movements in the treasury reference interest rate pending the issuance of the Notes. These treasury rate locks were terminated on May 11, 2005. The treasury rate lock agreements met the criteria for hedge accounting and were designated as a cash flow hedge. In accordance with cash flow hedge accounting, the Company recorded the loss associated with the fair value of the cash flow hedge of approximately $14.0 million, net of tax, as a component of accumulated other comprehensive loss. In May 2005, the Company began to recognize in earnings (as additional interest expense) the accumulated other comprehensive loss associated with the cash flow hedge. During the next twelve month period, approximately $0.3 million of this accumulated other comprehensive loss item will be reclassified to interest expense.
Contracts and Derivative Accounting. The Company uses commodity contracts to manage its exposure to price and availability risks for fuel purchases and power sales and purchases and these contracts generally have the characteristics of derivatives. The Company does not trade or use these
Index to Financial Statements EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
instruments with the objective of earning financial gains on the commodity price fluctuations. The Company has determined that all such contracts outstanding at December 31, 2006, except for certain natural gas commodity contracts with optionality features, that had the characteristics of derivatives met the “normal purchases and normal sales” exception provided in SFAS No. 133, and, as such, were not required to be accounted for as derivatives pursuant to SFAS No. 133 and other guidance.
The Company determined that certain of its natural gas commodity contracts with optionality features are not eligible for the normal purchases exception and, therefore, are required to be accounted for as derivative instruments pursuant to SFAS No. 133. However, as of December 31, 2006, the variable, market-based pricing provisions of existing gas contracts are such that these derivative instruments have no significant fair value.
Marketable Securities. The Company’s marketable securities, included in decommissioning trust funds in the balance sheets, are reported at fair value which was $114.7 million at December 31, 2006. Gross unrealized losses on marketable securities and the fair value of the related securities, aggregated by investment category and length of time that individual securities have been in a continuous unrealized loss position, at December 31, 2006, were as follows (in thousands):
The total impaired securities are comprised of approximately 80 investments that are in an unrealized loss position. The Company monitors the length of time the investment trades below its cost basis along with the amount and percentage of the unrealized loss in determining if a decline in fair value of marketable securities below original cost is considered to be other than temporary. In addition, the Company will research the future prospects of individual securities as necessary. As a result of these factors, as well as the Company’s intent and ability to hold these investments until their market price recovers, these investments are not considered other-than-temporarily impaired. The Company will not have a requirement to expend monies held in trust before 2024 or a later period when the Company begins to decommission Palo Verde. For 2006, the Company realized a $0.8 million gain on the sale of investments that were previously considered impaired. During the years ended December 31, 2006 and
Index to Financial Statements EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
2004, the Company recognized other than temporary impairment losses of marketable securities of $0.5 million and $0.3 million, respectively. The Company did not recognize any impairment losses for 2005.
N. Supplemental Statements of Cash Flows Disclosures
(1) The 2004 change is primarily related to a revaluation of investment tax credits as a result of the IRS settlement.
Index to Financial Statements EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
O. Selected Quarterly Financial Data (Unaudited)
(1) Operating revenues are seasonal in nature, with the peak sales periods generally occurring during the summer months. Comparisons among quarters of a year may not represent overall trends and changes in operations.
Index to Financial Statements
Item 9.
Item 9.
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A.
Item 9A.
Controls and Procedures
Evaluation of disclosure controls and procedures. During the period covered by this report, our chief executive officer and chief financial officer, after evaluating the effectiveness of the Company’s “disclosure controls and procedures” (as defined in the Securities Exchange Act of 1934 Rules 13a-15(e) and 15d-15(e)) as of December 31, 2006, (the “Evaluation Date”), concluded that as of the Evaluation Date, our disclosure controls and procedures (as required by paragraph (b) of the Securities Exchange Act of 1934 Rules 13a-15 or 15d-15) were adequate and designed to ensure that material information relating to us and our consolidated subsidiary would be made known to them by others within those entities.
Management’s Annual Report on Internal Control Over Financial Reporting. Included herein under the caption “Management Report on Internal Control Over Financial Reporting” on page 52 of this report.
Changes in internal control over financial reporting. There were no changes in our internal control over financial reporting in connection with the evaluation required by paragraph (d) of the Securities Exchange Act of 1934 Rules 13a-15 or 15d-15, that occurred during the quarter ended December 31, 2006, that materially affected, or that were reasonably likely to materially affect, our internal control over financial reporting.
Item 9B.
Item 9B.
Other Information
None.
Index to Financial Statements
PART III
Item 10.
Item 10.
Directors and Executive Officers of the Registrant
Information regarding directors is incorporated herein by reference from our definitive proxy statement for the 2007 Annual Meeting of Shareholders (the “2007 Proxy Statement”) under the heading “Nominee and Directors of the Company.” Information regarding executive officers, included herein under the caption “Executive Officers of the Registrant” in Part I, Item 1 above, is incorporated herein by reference.
The information concerning the identification of our standing audit committee required by this Item is incorporated by reference from the 2007 Proxy Statement under the caption “Committees” under the heading “Directors’ Meetings, Compensation and Committees,” and under the heading “Audit Committee Report.”
The information concerning our audit committee financial experts required by this Item is incorporated by reference from the 2007 Proxy Statement under the caption “Committees” under the heading “Directors’ Meetings, Compensation and Committees.”
The information concerning compliance with Section 16(a) of the Exchange Act required by this Item is incorporated by reference from the 2007 Proxy Statement under the heading “Section 16(a) Beneficial Ownership Reporting Compliance.”
We have adopted a Code of Ethics that is incorporated by reference from the 2007 Proxy Statement under the caption “Business Conduct Policies” under the heading “Corporate Governance.”
Item 11.
Item 11.
Executive Compensation
Incorporated herein by reference from the 2007 Proxy Statement under the heading “Summary of Compensation.”
Item 12.
Item 12.
Security Ownership of Certain Beneficial Owners and Management
Incorporated herein by reference from the 2007 Proxy Statement under the heading “Security Ownership of Certain Beneficial Owners and Management.”
Index to Financial Statements Equity Compensation Plan Information
Item 13.
Item 13.
Certain Relationships and Related Transactions
Incorporated herein by reference from the 2007 Proxy Statement under the heading “Certain Relationships and Related Party Transactions.”
Item 14.
Item 14.
Principal Accounting Fees and Services
Incorporated herein by reference from the 2007 Proxy Statement under the heading “Independent Registered Public Accounting Firm.”
PART IV
Item 15.
Item 15.
Exhibits and Financial Statement Schedules
(a) Documents filed as a part of this report:
Page
1.
Financial Statements:
See Index to Financial Statements
2.
Financial Statement Schedules:
All schedules are omitted as the required information is not applicable or is included in the financial statements or related notes thereto.
3.
Exhibits
Certain of the following documents are filed herewith. Certain other of the following exhibits have heretofore been filed with the Securities and Exchange Commission, and, pursuant to Rule 12b-32 and Regulation 201.24, are incorporated herein by reference.
Index to Financial Statements INDEX TO EXHIBITS
Index to Financial Statements INDEX TO EXHIBITS
Index to Financial Statements INDEX TO EXHIBITS
Index to Financial Statements INDEX TO EXHIBITS
Index to Financial Statements INDEX TO EXHIBITS
Index to Financial Statements INDEX TO EXHIBITS
Index to Financial Statements INDEX TO EXHIBITS
Index to Financial Statements INDEX TO EXHIBITS
Index to Financial Statements INDEX TO EXHIBITS
Index to Financial Statements INDEX TO EXHIBITS
* Filed herewith.
 Eleven agreements, dated March 10, 2005, substantially identical in all material respects to this exhibit, have been entered into with Gary R. Hedrick; J. Frank Bates; Scott D. Wilson; Steven P. Busser; Fernando Gireud; Kerry B. Lore; Robert C. McNiel; Hector Puente; Guillermo Silva, Jr.; John A. Whitacre; and Helen Williams Knopp; officers of the Company.
One agreement, dated July 11, 2005, substantially identical in all material respects to this exhibit, has been entered into with Andy Ramirez, officer of the Company.
One agreement, dated August 10, 2005, substantially identical in all material respects to this exhibit, has been entered into with David G. Carpenter, officer of the Company.
 One agreement, dated as of November 8, 2001, identical in all material respects to this exhibit, has been entered into with Gary R. Hedrick; officer of the Company.
Index to Financial Statements INDEX TO EXHIBITS
Exhibit
Number
Title
Nine agreements, dated as of February 28, 2002, substantially identical in all material respects to this Exhibit, have been entered into with J. Frank Bates; Gary R. Hedrick; Kathryn Hood; Helen Williams Knopp; Kerry B. Lore; Robert C. McNiel; Hector R. Puente; and Guillermo Silva, Jr.; officers of the Company.
Two agreements, dated as of July 15, 2002, substantially identical in all material respects to this Exhibit, have been entered into with Fernando J. Gireud and John A. Whitacre; officers of the Company.
Two agreements, dated as of December 4, 2003, substantially identical in all respects to this Exhibit, have been entered into with Steven P. Busser and Scott D. Wilson; officers of the Company.

Two agreements, dated January 3, 1998, identical in all material respects to this Exhibit, have been entered into with J. Frank Bates and Gary R. Hedrick; officers of the Company.
One agreement, dated as of May 28, 1999, identical in all material respects to this Exhibit, has been entered into with Helen Knopp; officer of the Company.
One agreement, dated as of January 3, 2000, identical in all material respects to this Exhibit, has been entered into with John C. Horne; officer of the Company.
One agreement, dated as of April 23, 2001, identical in all material respects to this Exhibit, has been entered into with Hector Puente; officer of the Company.
One agreement, dated as of November 5, 2001, identical in all material respects to this Exhibit, has been entered into with Gary R. Hedrick; officer of the Company.
One agreement, dated as of November 26, 2001, identical in all material respects to this Exhibit, has been entered into with J. Frank Bates; officer of the Company.
Three agreements, dated as of May 10, 2001, identical in all material respects to this Exhibit, have been entered into with Kathryn Hood, Kerry B. Lore and Guillermo Silva, Jr.; officers of the Company.
Two agreements, dated as of July 15, 2002, identical in all material respects to this Exhibit, have been entered into with Fernando J. Gireud and John A. Whitacre; officers of the Company.
Two agreements, dated as of December 4, 2003, identical in all material respects to this Exhibit, have been entered into with Steven P. Busser and Scott D. Wilson; officers of the Company.
Index to Financial Statements INDEX TO EXHIBITS
Exhibit
Number
Title

In lieu of non-employee director cash compensation, four agreements, dated as of January 3, 2005 and April 1, 2005, substantially identical in all material respects to this Exhibit, have been entered into with Kenneth R. Heitz and Patricia Z. Holland-Branch directors of the Company.
In lieu of non-employee director cash compensation, eleven agreements, dated as of May 4, 2005, substantially identical in all material respects to this Exhibit, were entered into with J. Robert Brown; James W. Cicconi; George W. Edwards, Jr.; Ramiro Guzman; James W. Harris; Kenneth R. Heitz; Patricia Z. Holland-Branch; Michael K. Parks; Eric B. Siegel; Stephen N. Wertheimer; and Charles A. Yamarone; directors of the Company.
In lieu of non-employee director cash compensation, four agreements, dated as of July 1, 2005 and October 1, 2005, substantially identical in all material respects to this Exhibit, have been entered into with Kenneth R. Heitz; and Patricia Z. Holland-Branch; directors of the Company.
In lieu of non-employee director cash compensation, four agreements, dated as of January 1, 2006 and April 1, 2006, substantially identical in all material respects to this Exhibit, have been entered into with Kenneth R. Heitz; and Patricia Z. Holland-Branch; directors of the Company.
In lieu of non-employee director cash compensation, eleven agreements, dated as of May 3, 2006, substantially identical in all material respects to this Exhibit, were entered into with J. Robert Brown; James W. Cicconi; George W. Edwards, Jr.; Ramiro Guzman; James W. Harris; Kenneth R. Heitz; Patricia Z. Holland-Branch; Michael K. Parks; Eric B. Siegel; Stephen N. Wertheimer; and Charles A. Yamarone; directors of the Company.
In lieu of non-employee director cash compensation, six agreements, dated as of July 1, 2006, October 1, 2006 and January 1, 2007, substantially identical in all material respects to this Exhibit, have been entered into with Kenneth R. Heitz; and Patricia Z. Holland-Branch; directors of the Company.

Eight agreements, dated as of May 8, 1997, identical in all material respects to this Exhibit have been entered into with George W. Edwards, Jr.; Ramiro Guzman; James W. Harris; Kenneth R. Heitz; Michael K. Parks; Eric B. Siegel; Stephen N. Wertheimer and Charles A. Yamarone; directors of the Company.
Ten agreements, dated as of May 29, 1998, identical in all material respects to this Exhibit have been entered into with George W. Edwards, Jr.; James W. Cicconi; Ramiro Guzman; James W. Harris; Kenneth R. Heitz; Patricia Z. Holland-Branch; Michael K. Parks; Eric B. Siegel; Stephen N. Wertheimer and Charles A. Yamarone; directors of the Company.
Index to Financial Statements INDEX TO EXHIBITS
Exhibit
Number
Title
In lieu of non-employee director cash compensation, two agreements, dated as of July 1, 2002 and October 1, 2002, substantially identical in all material respects to this Exhibit, have been entered into with Kenneth Heitz; director of the Company.
In lieu of non-employee director cash compensation, two agreements, dated as of January 1, 2003 and April 1, 2003, substantially identical in all material respects to this Exhibit, have been entered into with Kenneth Heitz; director of the Company.

Confidential treatment has been requested and received for the redacted portions of Exhibit 10.03. The copy filed herewith omits the information subject to the confidentiality request. Omissions are designated as “****.” A complete version of this Exhibit has been filed separately with the Securities and Exchange Commission.
Index to Financial Statements UNDERTAKING
Insofar as indemnification for liabilities arising under the Securities Act of 1933 may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act of 1933 and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question of whether such indemnification by it is against public policy as expressed in the Act and will be governed by the final adjudication of such issue.
Index to Financial Statements POWER OF ATTORNEY
KNOW ALL MEN BY THESE PRESENTS, that each of El Paso Electric Company, a Texas corporation, and the undersigned directors and officers of El Paso Electric Company, hereby constitutes and appoints Gary R. Hedrick, Scott D. Wilson, J. Frank Bates and Gary D. Sanders, its, his or her true and lawful attorneys-in-fact and agents, for it, him or her and its, his or her name, place and stead, in any and all capacities, with full power to act alone, to sign this report and any and all amendments to this report, and to file each such amendment to this report, with all exhibits thereto, and any and all documents in connection therewith, with the Securities and Exchange Commission, hereby granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform any and all acts and things requisite and necessary to be done in and about the premises, as fully to all intents and purposes as it, he or she might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or any of them, may lawfully do or cause to be done by virtue hereof.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on the 28th day of February 2007.
EL PASO ELECTRIC COMPANY
By:
/s/ GARY R. HEDRICK
Gary R. Hedrick
President and Chief Executive Officer
(Principal Executive Officer)
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated.