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 full requirements wholesale customer in Texas. The Company owns or has significant ownership interests in six electrical generating facilities providing it with a net dependable generating capability of approximately 1,643 MW. For the year ended December 31, 2009, the Company’s energy sources consisted of approximately 45% nuclear fuel, 22% natural gas, 7% coal, 26% purchased power and less than 1% generated by wind turbines.
The Company serves approximately 370,000 residential, commercial, industrial, public authority and wholesale customers. The Company distributes electricity to retail customers principally in El Paso, Texas and Las Cruces, New Mexico (representing approximately 64% and 11%, respectively, of the Company’s retail revenues for the year ended December 31, 2009). In addition, the Company’s wholesale sales include sales for resale to other electric utilities and power marketers. Principal industrial, public authority and other large retail 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, oil refining, two large universities, 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, 2010, the Company had approximately 1,000 employees, 42% of whom are covered by a collective bargaining agreement.
The Company makes available free of charge through its website, www.epelectric.com, its annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and all amendments to those reports as soon as reasonably practicable after such material is electronically filed with or furnished to the Securities and Exchange Commission (“SEC”). In addition, copies of the annual report will be made available free of charge upon written request. The SEC also maintains an internet site that contains reports, proxy and information statements and other information for issuers that file electronically with the SEC. The address of that site is www.sec.gov. The information on the internet site is not incorporated into this document by reference.
Facilities
The Company’s net dependable generating capability of 1,643 MW consists of the following:
Palo Verde Station
The Company owns a 15.8% interest, or approximately 633 MW, in 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 2025, 2026 and 2027, respectively. In addition, the Company is separately licensed by the NRC to own its proportionate share of Palo Verde. In December 2008, APS, as agent for the Palo Verde Participants, filed an application with the NRC to extend the Palo Verde licenses for 20 years. Approval, if granted, would be expected in 2011.
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.
Decommissioning. Pursuant to the ANPP Participation Agreement and federal law, the Company must fund its share of the estimated costs to decommission Palo Verde Units 1, 2 and 3,
including the Common Facilities, through the term of their respective operating licenses. The Company is required to maintain a minimum accumulation and a minimum funding level in its decommissioning account at the end of each annual reporting period during the life of the plant. The Company has established external trusts with an independent trustee which enables the Company to record a current deduction for federal income tax purposes for most of the amounts funded. At December 31, 2009, the Company’s decommissioning trust fund had a balance of $135.4 million and the Company was above its minimum funding level. The Company will continue to monitor the status of its decommissioning funds and adjust its deposits, if necessary, to remain at or above its minimum accumulation requirements in the future.
Decommissioning costs are estimated every three years based upon engineering cost studies performed by outside engineers retained by APS. On March 26, 2008, the Palo Verde Participants approved the 2007 Palo Verde decommissioning study (the “2007 Study”). The 2007 Study estimated that the Company must fund approximately $324.4 million (stated in 2007 dollars) to cover its share of decommissioning costs which was a reduction in decommissioning costs from the 2004 Palo Verde decommissioning study (the “2004 Study”) and will result in lower asset retirement obligations and lower expenses in the future. Although the 2007 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. See “Spent Fuel Storage” and “Disposal of Low-Level Radioactive Waste” below.
Spent Fuel Storage. The original spent fuel storage facilities at Palo Verde had sufficient capacity to store all fuel discharged from normal operation of all three Palo Verde units through 2003. Alternative on-site storage facilities and casks have been constructed to supplement the original facilities. In March 2003, APS began removing spent fuel from the original facilities as necessary, and placing it in special storage casks which will be stored at the new facilities until accepted by the DOE for permanent disposal. The 2007 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 current 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. In November 1997, the United States Court of Appeals for the District of Columbia Circuit issued a decision preventing the DOE from excusing its own delay but refused to order the DOE to begin accepting spent nuclear fuel. The Company cannot predict when spent fuel shipments to the DOE 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. On February 28,
2007, APS served on the U.S. Department of Justice its “Initial Disclosure of Claimed Damages” of $93.4 million (the Company’s portion being $14.8 million). This amount includes expenses associated with design, construction, loading, and operation of the Palo Verde independent spent fuel storage installation through December 2006. This amount represents costs incurred to ensure sufficient storage capacity for Palo Verde spent fuel that would not have been incurred had the DOE complied with its standard contract obligation to begin accepting spent fuel from the commercial nuclear power industry beginning in 1998. A trial was held for this case in 2009. The Court has not indicated when it will reach a decision in the matter.
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. The construction and opening of low-level radioactive waste disposal sites has been delayed due to extensive public hearings, disputes over environmental issues and review of technical issues related to the proposed sites. The opposition, delays, uncertainty and costs that have been experienced demonstrate possible roadblocks that may be encountered when Arizona seeks to open its own waste repository. APS currently believes that interim low-level waste storage methods are or will be available to allow each Palo Verde unit to continue to operate and to store safely low-level waste until a permanent disposal facility is available.
Reactor Vessel Heads. In accordance with applicable NRC requirements, APS conducts regular inspections of reactor vessel heads at Palo Verde Units 1, 2 and 3. In an effort to reduce long-term operating costs at the station related to inspection of the reactor heads, related equipment, and possible repair costs, APS is replacing reactor vessel heads at Palo Verde. The replacement of the Unit 2 reactor vessel head was successfully completed during the fall 2009 refueling outage. Reactor vessel head replacement is scheduled to occur at Units 1 and 3 in 2010. The Company’s share of the cash requirements for this project is estimated to be $21.1 million of which $11.9 million had been expended at December 31, 2009.
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 $12.6 billion. This potential liability is covered by primary liability insurance provided by commercial insurance carriers in the amount of $375 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 $117.5 million, subject to an annual limit of $17.5 million. 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 $55.7 million, with an annual payment limitation of approximately $8.3 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 $10.6 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 two combined cycle generating units including a 288 MW combined cycle generating unit designated as Newman Unit 5. Construction of Newman Unit 5 began in July 2008 and will be completed in two phases. The first phase, consisting of two 70 MW gas turbine generators, was completed in May 2009. The second phase will add two heat recovery steam generators and a steam turbine with an expected net capability of 148 MW and is currently expected to be completed before the summer of 2011. The current aggregate net capability of the Newman Power Station is approximately 614 MW. Units 1-4 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 net capability of approximately 229 MW. The units operate primarily on natural gas but can also operate on fuel oil.
Four Corners Station
The Company owns a 7% interest, or approximately 104 MW, in Units 4 and 5 at Four Corners, located in northwestern New Mexico. Each of the two coal-fired generating units has a total net capability of 739 MW. The Company shares power entitlements and certain allocated costs of the two units with APS (the Four Corners operating agent) and the other participants, PNM, TEP, SCE and SRP.
Four Corners is located on land under easements from the federal government and a lease from the Navajo Nation that expires in 2016, with a one-time option to extend the term for an additional 25 years. Certain of the facilities associated with Four Corners, including transmission lines and almost all of the contracted coal sources, are also located on Navajo land. Units 4 and 5 are located adjacent to a surface-mined supply of coal.
Copper Power Station
The 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 10%, is used as net capability for resource planning purposes.
Transmission and Distribution Lines and Agreements
The Company owns or has significant ownership interests in four 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 and the Western Electricity Coordinating Council, the Company operates its transmission system in a way that allows it to maintain system integrity in the event that any one of these transmission lines is out of service.
Springerville-Luna-Diablo Line. The Company owns a 310-mile, 345 kV transmission line from 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.
West Mesa-Arroyo Line. The Company owns a 202-mile, 345 kV transmission line from PNM’s West Mesa Substation located near Albuquerque, New Mexico, to the Company’s Arroyo Substation located near Las Cruces, New Mexico. West Mesa Substation is the primary delivery point for the Company’s generation entitlement from Four Corners, which is transmitted from Four Corners to the West Mesa Substation over approximately 150 miles of transmission lines owned by PNM.
Greenlee-Hidalgo-Luna-Newman Line. The Company owns 40% of a 60-mile, 345 kV transmission line between 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.
Eddy County-AMRAD Line. The Company owns 66.7% of a 125-mile, 345 kV transmission line from the Company’s and PNM’s high voltage direct current terminal at the Eddy County Substation near Artesia, New Mexico to the AMRAD Substation near Oro Grande, New Mexico. The Company also 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. The Company also owns 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 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
Environmental Regulation. The Company is subject to regulation with respect to air, soil and water quality, solid waste disposal and other environmental matters by federal, state, tribal and local authorities. Those authorities govern current facility operations and have continuing jurisdiction over facility modifications. Failure to comply with these environmental regulatory requirements can result in actions by regulatory agencies or other authorities that might seek to impose on the Company administrative, civil and/or criminal penalties. In addition, unauthorized releases of pollutants or contaminants into the environment can result in costly cleanup obligations that are subject to enforcement by regulatory agencies. These laws and regulations are subject to change and, as a result of those changes, the Company may face additional capital and operating costs to comply.
Another way in which environmental matters may impact the Company’s operations and business is the implementation of the U.S. Environmental Protection Agency’s (“EPA”) Clean Air Interstate Rule (“CAIR”) which, as applied to the Company, may result in a requirement that it substantially reduce emissions of nitrogen oxides from its power plants in Texas and/or purchase allowances representing other parties’ emissions reductions starting in 2009. These requirements become more stringent in 2015, and are anticipated to require even further emissions reductions or additional allowance purchases. On July 11, 2008, the U.S. Court of Appeals for the District of Columbia vacated CAIR in its entirety. On December 23, 2008 the Court of Appeals granted rehearing and instead remanded CAIR without vacating the original regulation. As a result, the Company must comply with CAIR as written until the EPA rewrites the CAIR rule as required by the Court’s final opinion. The 2009 reconciliation to comply with CAIR is due March 2010 and the Company had accrued $0.5 million at December 31, 2009 to purchase the estimated credits needed to meet its requirement.
Climate Change. A significant portion of the Company’s generation assets are nuclear or gas-fired, and as a result, the Company believes that its greenhouse gas emissions are low relative to electric power companies who rely on more coal-fired generation. However, regulations governing the emission of greenhouse gases, such as carbon dioxide, could impose significant costs or limitations on the Company. The U.S. Congress is considering new legislation to restrict or regulate greenhouse gas emissions. The American Clean Energy and Security Act of 2009, which was passed by the U.S. House of Representatives in 2009, could, if enacted by the full Congress, require greenhouse gas emissions reductions by covered sources of as much as 17% from 2005 levels by 2020 and by as much as 83% by 2050. In addition, almost half of the states, either individually or through multi-state regional initiatives, have begun to consider how to address greenhouse gas emissions, and are actively considering the development of emission inventories or regional greenhouse gas cap and trade programs. The State of New Mexico, where we operate one facility and have an interest in another facility, has joined with California and several other states in the Western Climate Initiative and is pursuing initiatives to reduce greenhouse gas emissions in the state. If and when the United States or individual states in which we operate regulate greenhouse gas emissions, the Company’s fossil fuel generation assets are likely to face additional costs for monitoring, reporting, and controlling, or offsetting these emissions, as well as for controlling emissions or purchasing and surrendering allowances for greenhouse gas emissions resulting from our operations.
Also, as a result of the U.S. Supreme Court’s decision on April 2, 2007 in Massachusetts, et al. v. EPA, on December 15, 2009, the EPA officially published its finalized determination that emissions of carbon dioxide, methane and other greenhouse gases present an endangerment to human health and welfare because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. Following that determination, the EPA has said it will, in March 2010, finalize regulation under its existing Clean Air Act (“CAA”) authority governing greenhouse gas emissions, including regulating emissions from large stationary sources, such as the fossil fuel-fired power plants operated by the Company, even if Congress does not adopt new legislation specifically addressing emissions of greenhouse gases. In addition, in September 2009, the EPA adopted a new rule requiring approximately 10,000 facilities comprising a substantial percentage of annual U.S. greenhouse gas emissions to inventory their emissions starting in 2010 and to report those emissions to the EPA beginning in 2011. The Company’s fossil fuel-fired power generating assets are subject to this rule.
Finally, as part of ongoing international discussions relating to climate change, on January 28, 2010, the United States formally submitted an emissions reduction target to the United Nations stating that the United States would cut its emissions in the range of 17% from 2005 levels by 2020, conditional on congressional action on climate change.
It is not currently possible to predict with confidence how any proposed or future greenhouse gas legislation by Congress, the states, or multi-state regions or regulations adopted by EPA or the state environmental agencies will impact our business. However, any such legislation or regulation of greenhouse gas emissions or any future related litigation could result in increased compliance costs or additional operating restrictions or increased or reduced demand for the power we generate, could require us to purchase rights to emit greenhouse gases, and could have a material adverse effect on our business, financial condition, reputation or results of operations.
Climate change also has potential physical effects that could be relevant to the Company’s business. In particular, some studies suggest that climate change could affect our service area by causing higher temperatures, less winter precipitation and less spring runoff, as well as by causing more extreme weather events. Such developments could change the demand for power in the region and could also impact the price or ready availability of water supplies or affect maintenance needs and the reliability of Company equipment.
The Company takes these regulatory and physical factors seriously and we will monitor these issues so that the Company can adapt to any such changes. We are already performing continuous emission monitoring for carbon dioxide emissions from the power plants we operate. We also have carefully inventoried and adopted controls for our equipment that contains sodium hexafluoride, another greenhouse gas. We are tracking our greenhouse gas emissions pursuant to EPA’s new inventory rule.
Some of our operations may benefit from additional regulation of greenhouse gas emissions. National studies performed by environmental organizations suggest that emissions of carbon dioxide from the Company’s generating facilities are low relative to other electric power companies, both in absolute terms and in terms of emissions per unit of electricity produced. This is because a significant portion of the Company’s generation assets are nuclear or gas-fired, which fuels are often viewed as
having no and lower emissions of greenhouse gases, respectively, than some other types of fossil fuel generation facilities. Accordingly, the Company does not believe greenhouse gas regulations would impose greater relative burdens on the Company than on most other electric utilities. Nonetheless, we believe that material effects on the Company’s business or operations may result from the physical consequences of climate change, the regulatory approach to climate change ultimately selected and implemented by governmental authorities, or both. Given the very significant remaining uncertainties regarding whether and how these issues will be regulated, as well as the timing and severity of any physical effects of climate change, we believe it is impossible at present to meaningfully quantify the costs of these potential impacts.
The Company takes its environmental compliance seriously and is monitoring these issues so that the Company is able to adapt to any changes. While the Company strives to prepare for and implement actions necessary to comply with changing environmental regulations, substantial expenditures may be required for the Company to comply with such regulations in the future and, in some instances, those expenditures may be material. The Company believes it is impossible at present to meaningfully quantify the costs of these potential impacts.
Ongoing Regulatory Compliance. The Company analyzes the costs of its current obligations arising from environmental matters on an ongoing basis and believes it has made adequate provision in its financial statements to meet the obligations which can be meaningfully quantified. As a result of this analysis, the Company has a provision for environmental remediation obligations of approximately $1.2 million as of December 31, 2009, related to compliance with federal and state environmental standards. However, unforeseen expenses associated with environmental compliance or remediation may occur and could have a material adverse effect on the future operations and financial condition of the Company.
Along with many other companies, the Company received from the Texas Commission on Environmental Quality (“TCEQ”) a request for information in 2003 in connection with environmental conditions at a facility in San Angelo, Texas that was operated by the San Angelo Electric Service Company (“SESCO”). In November 2005, TCEQ proposed the SESCO site for listing on the registry of Texas state superfund sites and mailed notice to more than five hundred entities, including the Company, indicating that TCEQ considers each of them to be a “potentially responsible party” 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. In November 2009 the Company made an offer to the SESCO working group to settle this matter and a response is pending. 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.
The EPA has investigated releases or potential releases of hazardous substances, pollutants or contaminants at the Gila River Boundary Site, on the Gila River Indian Community (“GRIC”) reservation in Arizona and designated it as a Superfund Site. The Company currently owns 16.29% of the site and will share in the cost of cleanup of this site. The Company has a tentative agreement between the former property owner and the EPA to settle this matter for less than $0.1 million and the Company has accrued $0.2 million for potential costs related to this matter.
On September 30, 2008, the State of New Mexico, acting on behalf of the New Mexico Environment Department (“NMED”), filed a complaint in New Mexico district court alleging that, on approximately 650 occasions between May 2000 and September 2005, the Company’s Rio Grande
Power Station, located in Dona Ana County, New Mexico, 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 NMED originally made these allegations in a compliance order which the NMED withdrew simultaneously with the filing of the complaint in district court. On October 27, 2008, the State of New Mexico amended its complaint to allege approximately 300 additional exceedances of permitted nitrogen dioxide and carbon monoxide emission rates and associated reporting failures between October 2005 and July 2007. The amended complaint sought civil penalties in the amount of $15,000 per day for each alleged violation. On July 30, 2009, the Company and NMED entered into a consent decree resolving all issues in this suit. In the consent decree, the Company denied any violations of air emissions standards but agreed to pay a civil penalty of $0.3 million to avoid further defense costs in this matter. In addition, the Company agreed to complete a supplemental environmental project at the Rio Grande Power Station at a cost not to exceed $0.3 million. The New Mexico district court approved the consent decree and dismissed the lawsuit on July 31, 2009.
In 2006, the Company experienced an oil discharge at the Rio Grande Power Station. The Company remediated the site by removing the contaminated soil and installing monitoring wells to monitor for the presence of hydrocarbons in the ground water. Recently, a monitoring well showed signs of contamination at levels exceeding New Mexico ground water standards. The Company notified the NMED of its findings and submitted an abatement plan to the NMED addressing the soil and ground water impacts. Upon approval of the abatement plan by the NMED, the Company will begin a detailed assessment of the site and perform further remediation of the site as appropriate. The Company has accrued $0.3 million for potential costs related to this matter.
In May 2007, the EPA finalized a new federal implementation plan which addresses emissions at the Four Corners Power Station in northwestern New Mexico of which the Company owns a 7% interest in Units 4 and 5. APS, the Four Corners operating agent, has filed suit against the EPA relating to this new federal implementation plan in order to resolve issues involving operating flexibility for emission opacity standards. The Company cannot predict the outcome of the suit filed against the EPA or whether compliance with the new requirements could have an adverse effect on its capital and operating costs.
On April 6, 2009, APS received a request from the EPA under Section 114 of the CAA seeking detailed information regarding projects and operations at Four Corners. APS has responded to this request. The Company is unable to predict the timing or content of EPA’s response or any resulting actions.
On February 16, 2010, a group of environmental organizations filed a petition with the United States Departments of Interior and Agriculture requesting that the agencies certify to the EPA that emissions from Four Corners are causing “reasonably attributable visibility impairment” under the CAA. APS is currently reviewing the petition and has indicated that it will likely file a response in opposition to the petition. The Company cannot predict the outcome of the petition or whether any resulting actions could have an adverse effect on its capital or operating costs.
In December 2008, El Paso notified the Company that a property purchased from the Company in May 2005 contained subsurface contamination. The Company and El Paso disposed of contaminated materials and in April 2009, the TCEQ notified the parties that no further clean-up was required. The Company’s remediation expense was less than the reserve previously established for this site, and the Company recorded a reduction in environmental expense of $0.6 million in the second quarter of 2009.
Except as described herein, the Company is not aware of any other active investigation of its compliance with environmental requirements by the EPA, the TCEQ or the NMED 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, and the cost of capital improvements and replacements at Palo Verde. Studies indicate that the Company will need additional power generation resources to meet increasing load requirements on its system and to replace retiring plants and terminated purchased power agreements, the costs of which are included in the table below.
The Company’s estimated cash construction costs for 2010 through 2013 are approximately $849 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 $255 million for new gas-fired generating capacity (including $68 million for Newman Unit 5), and $32 million for other local generation, $35 million for the Four Corners Station and $148 million for the Palo Verde Station.
Energy Sources
General
The following table summarizes the percentage contribution of nuclear fuel, natural gas, coal and purchased power to the total kWh energy mix of the Company. Energy generated by wind turbines accounted for less than 1% of the total kWh energy mix.
Allocated fuel and purchased power costs are generally recoverable from customers in Texas and New Mexico pursuant to applicable regulations. Historical fuel costs and revenues are reconciled
periodically in proceedings before the PUCT 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 or are currently negotiating contracts that when combined with the current inventory will furnish 100% of Palo Verde’s operational requirements for uranium concentrates, and conversion services through 2011. In addition, the Palo Verde Participants have contracted for 100% of enrichment services through 2013 and 100% of fabrication services until at least 2016 for each Palo Verde unit.
Nuclear Fuel Financing. Pursuant to the ANPP Participation Agreement, the Company owns an undivided interest in nuclear fuel purchased in connection with Palo Verde. The Palo Verde Participants have sought to mitigate the effects of potential supply disruptions and price increases by employing a procurement strategy where (i) nuclear fuel arrives on site up to three months before being loaded and (ii) a strategic inventory of converted nuclear fuel material sufficient to provide feed stock for one full reactor reload is stored for future use.
The Company has available $200 million under a revolving credit facility which provides for both working capital and up to $120 million for the financing of nuclear fuel. This facility has a five-year term ending April 11, 2011. This financing is accomplished through a trust that borrows under the credit facility to acquire and process the nuclear fuel. The Company is obligated to repay the trust’s borrowings with interest and the assets and liabilities of the trust are consolidated and reported as assets and liabilities of the Company. At December 31, 2009, approximately $107.0 million had been drawn to finance nuclear fuel. If additional funds are required to finance nuclear fuel, the Company may borrow additional funds under its credit facility or enter into a new credit facility to finance nuclear fuel.
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 2009, the Company’s natural gas requirements at the Newman and Rio Grande Power Stations were met with both short-term and long-term natural gas purchases from various suppliers, and this practice is expected to continue in 2010. 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 Stations. The Company will continue to evaluate the availability of short-term natural gas supplies versus long-term supplies to maintain a reliable and economical supply for the Newman and Rio Grande Power Stations.
Natural gas for the Newman and Copper Power Stations is also supplied pursuant to an intrastate natural gas contract that became effective October 1, 2009 and continues through 2017. The agreement replaced the previous intrastate natural gas supply contract that expired in 2007 but had been extended by letter agreement from month to month until the new agreement became effective.
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. The Company received notice from SPS in late 2006 that SPS had been subject to adverse regulatory action by the PUCT regarding transactions under the contract and that SPS wished to exercise its right to terminate the contract early. As a result, on January 29, 2008, the Company and SPS entered into an amendment to the contract and the contract terminated on September 30, 2009.
The Company initiated a Power Purchase and Sale Agreement with Phelps Dodge Energy Services LLC (“Phelps Dodge”) in June 2006. The contract provides for Phelps Dodge to deliver energy to the Company from its ownership interest in the Luna Energy Facility (a 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 Greenlee, Arizona. The Company may purchase up to 100 MW at a specified price at times when energy is not exchanged under the Power Purchase and Sale Agreement. Upon mutual agreement, the contract allows the parties to increase the amount of energy that is purchased and sold under the Power Purchase and Sale Agreement. The parties have agreed to increase the amount to 125 MW for a period of 25 months beginning December 1, 2008. The contract was approved by the FERC and continues through December 31, 2021.
The Company entered into an agreement to purchase capacity and unit contingent energy from Shell Energy North America (“Shell”). Under the agreement, the Company provides natural gas to Pyramid Unit No. 4 where Shell has the right to convert natural gas to electric energy. The Company may schedule up to 100% of Pyramid Unit No. 4’s output, approximately 40 MW, from January 1, 2010 through December 31, 2010.
The Company entered into a 20-year contract with New Mexico SunTower, LLC (“eSolar”) on October 17, 2008. The contract is a power purchase agreement for the full capacity of a 92 MW concentrated solar plant to be built in Southern New Mexico. The plant is scheduled to begin commercial operation in 2011.
Other purchases of shorter duration were made during 2009 to replace the Company’s generation resources during planned and unplanned outages and for economic reasons as well as to supply off-system sales.
Operating Statistics
(1) 2009 includes a 140,000 kW increase in generating capability at Newman related to the completion of the first phase of the Newman Unit 5 construction which consists of two 70,000 kW gas turbine generators. 2008 includes an 11,000 kW increase in generating capability at Palo Verde related to the steam generator replacements for Unit 3.
(2) Includes spot firm sales and net losses of 152,000 kW, 145,000 kW and 172,000 kW for 2009, 2008 and 2007, respectively.
(3) Excludes 233,000 kW, 333,000 kW and 233,000 kW for 2009, 2008 and 2007, respectively, of firm on-peak purchases.
Regulation
General
The rates and services of the Company are regulated by incorporated municipalities in Texas, the PUCT, the NMPRC, and the FERC. The PUCT 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 and compliance with federally-mandated reliability standards. The decisions of the PUCT, NMPRC and the FERC are subject to judicial review.
Texas Regulatory Matters
Texas Freeze Period. The Company has entered into agreements (“Texas Rate Agreements”) with El Paso, PUCT staff and other parties in Texas that provide for most retail base rates to remain at their current level through June 30, 2010. During the rate freeze period, if the 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 an amount equal to 50% of the Texas jurisdictional pretax return in excess of the ceiling. The range is based upon a risk premium analysis used in rate proceedings to establish a utility’s return on equity, and as of December 31, 2009, the range would be approximately 9.06% to 13.06%. The Company’s return on equity fell within this range during 2009. Also pursuant to the Texas Rate Agreements, the Company agreed to share with its Texas customers 25% of off-system sales margins increasing to 90% after June 30, 2010 through June 30, 2015.
Fuel and Purchased Power Costs. Although the Company’s base rates are frozen pursuant to the Texas Rate Agreements, the Company’s actual fuel costs, including purchased power energy costs, are recoverable from its customers. The PUCT has adopted a rule establishing the recovery of fuel costs (“Texas Fuel Rule”) that allows the Company to seek adjustments to its fixed fuel factor three times per year in February, June and October. The Texas Fuel Rule provides for the fixed fuel factor to be based upon projected fuel and purchased power costs and projected kilowatt-hour sales for a twelve-month period. The Texas Fuel Rule also allows for the Company to request a formula to determine its fuel factor. Once a formula is approved, the Company could seek to revise its fixed fuel factor based upon the approved formula at least four months after its last revision except in the month of December. The Texas Fuel Rule requires the Company to request to refund fuel costs in any month when the over-recovery balance exceeds a threshold material amount and it expects to continue to be materially over-recovered. The Texas Fuel Rule also permits the Company to seek to surcharge fuel under-recoveries in any month the balance exceeds a threshold material amount and it expects to continue to be materially under-recovered. Fuel over and under recoveries are considered material when they exceed 4% of the previous twelve months fuel costs. All such fuel revenue and expense activities are subject to periodic final review by the PUCT in fuel reconciliation proceedings.
On January 8, 2008, the Company filed a request with the PUCT in Docket No. 35204 to surcharge approximately $30.1 million, including interest, of under-recovered fuel and purchased power costs to be collected over a twelve-month period. The fuel under-recoveries were incurred during the period December 2005 through November 2007. On April 11, 2008, the PUCT issued a final order approving the fuel surcharge to be collected over a twelve-month period beginning in May 2008.
On July 8, 2008, the Company filed a petition in Docket No. 35856 with the PUCT to increase its fixed fuel factors and to surcharge $39.5 million of under-recovered fuel and purchased power costs including interest. The surcharge was based upon actual under-recoveries for the period December 2007 through May 2008 and expected under-recoveries for June and July 2008. On September 25, 2008, the PUCT issued a final order approving an increase in the Company’s Texas jurisdictional fixed fuel factors of $38.8 million or 21.5% annually beginning with customer bills rendered in October 2008. In addition, the PUCT approved the recovery of $39.5 million in fuel under-recoveries over an 18-month period beginning in October 2008.
On April 1, 2009, the Company filed a petition with the PUCT in Docket No. 36864 to terminate the interim fuel surcharge which had been authorized in Docket No. 35856. The Company’s request was a result of the over-recovery of fuel costs under the Company’s fixed fuel factor effective in October 2008 which largely offset the remaining balance of the fuel surcharge. The fuel over-recoveries were the result of the significant drop in natural gas prices since the fixed fuel factor went into effect in October 2008. On April 23, 2009, the Company received approval from the PUCT to terminate the fuel surcharge effective for customer bills rendered in May 2009 and thereafter.
On June 5, 2009, the Company filed a petition with the PUCT in Docket No. 37086 to decrease its fixed fuel factors by 13.1%, or $27.9 million. On July 30, 2009, the PUCT approved the new factors effective for customer bills rendered beginning in August 2009.
On September 1, 2009, the Company filed a petition in Docket No. 37433 to refund $12.0 million in fuel cost over-recoveries, including interest, for the period of July 2008 through July 2009. The Company entered into a stipulation in October 2009 that included the August 2009 over-recovery in the refund for a total of $16.8 million, including interest, and provided for the refund to be paid in November and December, 2009. On October 23, 2009, the PUCT issued an order approving the stipulation.
On December 17, 2009, the Company filed a petition with the PUCT Docket No. 37788 requesting authority to implement a one-month, interim fuel refund of $11.8 million in fuel cost over-recoveries, including interest, for the period September through November 2009. On January 20, 2010, a stipulation was filed that resolves all of the issues in this proceeding. The stipulation provides for the Company to implement a fuel refund for the net over-recovery of $11.8 million, including interest, in the month of February, 2010. On January 21, 2010, the administrative law judge assigned to the docket issued an order approving the implementation of interim rates to allow the requested refund to be made. The PUCT approved the stipulation at its open meeting on February 11, 2010.
Palo Verde Performance Standards. The PUCT established performance standards for the operation of Palo Verde pursuant to which each Palo Verde unit is evaluated annually to determine whether its three-year rolling average capacity factor entitles the Company to a reward or subjects it to a penalty. The capacity factor is calculated as the ratio of actual generation to maximum possible generation. If the capacity factor, as measured on a station-wide basis for any consecutive 36-month period, should fall below 35%, the parties to the Texas Rate Agreements can seek to remove Palo Verde from base rates and 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 2009, 2008 and 2007 to be approximately $0.7 million, $0.1 million, and $0.6 million, respectively. Performance rewards are not recorded on the Company’s books until the PUCT has made 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.
The Company agreed to contribute Palo Verde rewards approved in its fuel reconciliation proceeding in PUC Docket No. 23530 to assist low-income customers in paying their utility bills. In compliance with the PUCT order, the Company sought and received approval by the El Paso City Council in January 2006 to remit to El Paso approximately $5.8 million in Palo Verde performance reward funds to fund demand side management programs such as weatherization with a focus on programs to assist small business and commercial customers. As of December 31, 2009, $2.5 million, including accrued interest, remains to be paid under these agreements and is recorded as a liability on the Company’s balance sheet.
Renewable Energy Requirements. Notwithstanding the PUCT’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 is required to annually obtain its pro rata share of renewable energy credits as determined by the Electric Reliability Council of Texas (the “Program Administrator”). 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 expects to meet its obligations for renewable energy credits for 2009.
2007 Energy Efficiency Legislation. The Texas legislature has established energy efficiency goals for cost-effective energy efficiency for residential and commercial customers equivalent to at least 15% of the annual growth in demand by December 31, 2008 and 20% of the annual growth in demand by December 31, 2009. Among other things, the legislation requires the PUCT to establish an energy efficiency cost recovery factor for ensuring cost recovery for utility expenditures made to satisfy the energy efficiency goal. The legislation provides that utilities that are unable to establish an energy efficiency cost recovery factor in a timely manner due to a rate freeze will be allowed to defer the costs of complying with the energy efficiency goal and recover such deferred costs at the end of the rate freeze period. On September 8, 2008 in Docket No. 35612, the PUCT approved the Company’s request to defer these costs and recover them through a cost recovery factor upon expiration of its rate freeze period. As of December 31, 2009, the Company had deferred as a regulatory asset, $4.0 million of energy efficiency costs.
2009 Texas Retail Rate Case. On December 9, 2009, the Company filed an application with the PUCT for authority to change rates, to reconcile fuel costs, to establish formula-based fuel factors, and to establish an energy efficiency cost-recovery factor. This case was assigned PUCT Docket No. 37690. The test year for the base-rate case is July 2008 through June 2009. The Company seeks to increase its base-rate revenue requirement by $51.6 million over current base rates, or a 12.89% annual increase, based on a total non-fuel base revenue requirement of $451.7 million for the Company’s retail jurisdiction. The Company’s fuel-reconciliation request addresses fuel and purchased power costs and fuel-factor revenues for the period March 1, 2007 through June 30, 2009. The Company’s request to implement a fuel-factor formula would change its historically-used method of establishing fuel and purchased power costs based upon a projected test year period to a PUCT-approved, utility-specific formula pursuant to PUCT Rules. Finally, the Company’s request to implement an energy-efficiency cost-recovery factor would recover its ongoing reasonable energy-efficiency costs in addition to the previous costs that were deferred for future recovery due to the Company’s rate freeze.
On January 20, 2010, the administrative law judge issued an order approving an agreed procedural schedule that provides for intervenor and staff testimony with their recommended rate changes to be filed in April and hearings to begin on May 10, 2010. The agreed procedural schedule provides that, if the PUCT has not approved final rates by August 20, 2010, current rates will be in effect on a temporary basis from such date, subject to true-up to the final approved base rates.
Electric Restructuring. The Texas Restructuring Law required certain investor-owned electric utilities to separate power generation activities and retail service activities from transmission and distribution activities by January 1, 2002, and on that date, retail competition for generation services was instituted in some parts of Texas. However, the PUCT has delayed retail competition in the Company’s Texas service territory by approving a rule which identifies various milestones for the Company to reach before competition can begin. The first milestone calls for the development, approval by the FERC, and commencement of independent operation of a regional transmission organization (“RTO”) in the area that includes the Company’s service territory, including the development of retail market protocols to facilitate retail competition (see “FERC Regulatory Matters - RTOs” below). The complete transition to retail competition would occur upon the completion of the last milestone, which would be the PUCT’s final evaluation of the market’s readiness to offer fair competition and reliable service to all retail customers. The Company believes this rule delays retail competition in its Texas service territory indefinitely. There is substantial uncertainty about both the regulatory framework and market conditions that will exist if and when retail competition is implemented in the 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, if it were to be implemented.
New Mexico Regulatory Matters
2007 New Mexico Stipulation. In July 2007, the NMPRC issued a final order approving a stipulation (“2007 New Mexico Stipulation”) addressing all issues in the 2006 rate filing in Case No. 06-00258-UT. The 2007 New Mexico Stipulation provided for a $5.8 million non-fuel base rate increase, established the amount of fuel included in base rates at $0.04288 per kWh, and modified the Company’s Fuel and Purchased Power Cost Adjustment Clause (the “FPPCAC”). Any difference between actual fuel and purchased power costs and the amount included in base rates was recovered or refunded through the FPPCAC. Rates continued in effect until changed by the NMPRC following the Company’s next rate case. The 2007 New Mexico Stipulation required the Company to file its next general rate case no later than May 29, 2009 using as a base period the twelve months ending December 31, 2008. Under NMPRC statutes, new rates would become effective no later than July 2010 unless otherwise extended. The Company complied with the 2007 New Mexico Stipulation and filed its required rate case on May 29, 2009.
The 2007 New Mexico Stipulation provided for recovery through the FPPCAC of the cost of capacity and energy provided to New Mexico retail customers from the deregulated Palo Verde Unit 3. The amount to be recovered was based upon the monthly contract cost of capacity and energy for power purchased under the Southwestern Public Service Company (“SPS”) purchased power contract. In February and March 2009, the volumes delivered to the Company over the transmission tie used to import SPS power were materially lower than normal due to operational constraints. This reduction in volume resulted in contract formula prices for Palo Verde Unit 3 power that were significantly higher than what were foreseen by the 2007 New Mexico Stipulation. The Company addressed this price spike
due to operational constraints by proposing to adjust the proxy price in February 2009 to $54.27 per MWh (January 2009 monthly calculated price) and in March 2009 to $64.38 per MWh (12 months ending January 2009 average price) which is approximately 28% and 55% of the price calculated utilizing the formula from the 2007 New Mexico Stipulation. Because the operational constraints limiting the SPS purchases were expected to continue during 2009, the Company on April 24, 2009 requested approval of an unopposed variance to the calculation of the Palo Verde Unit 3 proxy price to be the lower of the monthly cost of capacity and energy under the SPS purchased power contract or the average cost of capacity and energy under the SPS purchased power contract for the twelve months ended January 2009 of $64.38 per MWh.
The SPS purchased power contract was terminated September 30, 2009, see Note J of the Notes to Consolidated Financial Statements. The 2007 New Mexico Stipulation provided that upon termination of the SPS contract, the proxy price would be the average cost of SPS capacity and energy during the twelve months prior to contract termination. As a result, the price of deregulated Palo Verde Unit 3 power was set at $47.77 during the months of October 2009 through December 2009.
The 2007 New Mexico Stipulation also required 25% of jurisdictional off-system sales margins to be credited to customers through the FPPCAC until July 2010 when 90% of jurisdictional off-system sales margins will be credited to customers.
2009 New Mexico Stipulation. On May 29, 2009, the Company filed with the NMPRC a petition to increase non-fuel and purchased power base rates by $12.7 million annually. The filing reflected a projected reduction of $21.3 million in fuel related revenues based upon the difference in revenues for the test year ended December 31, 2008 and the forecast period revenues (forecasted fuel and purchased power costs for the twelve month period beginning July 1, 2010) for a projected net decrease in New Mexico jurisdictional fuel and purchased power revenues of $8.6 million. The filing complied with the 2007 New Mexico Stipulation requirement in the NMPRC’s Final Order in Case No. 06-00258-UT to file a general rate case by May 30, 2009 using a test year ended December 31, 2008. The 2009 rate case was docketed as NMPRC Case No. 09-00171-UT.
A unanimous settlement of all issues in the case and an unopposed, comprehensive stipulation (the “2009 New Mexico Stipulation”) was filed on October 8, 2009. The 2009 New Mexico Stipulation resolved all issues and provided for an increase in New Mexico jurisdictional non-fuel and purchased power base rate revenues of $5.5 million. The 2009 New Mexico Stipulation provided for the revision of depreciation rates for the Palo Verde nuclear generating plant to reflect a 20-year life extension and depreciation rates for other plant in service. The 2009 New Mexico Stipulation also provided for the continuation of the Company’s FPPCAC without conditions or variance and established the base fuel factor at $0.04362 per kWh. In addition, the 2009 New Mexico Stipulation modified the market pricing of capacity and energy provided by Palo Verde Unit 3 due to the termination of the SPS contract in September 2009. Pursuant to the 2009 New Mexico Stipulation, Palo Verde Unit 3 capacity and energy will be included in the FPPCAC based upon an existing purchased power contract with Credit Suisse Energy, LLC.
The Company and Staff filed testimony in support of the 2009 New Mexico Stipulation on October 22, 2009. A public evidentiary hearing on the merits of the 2009 New Mexico Stipulation was held before the Commission on November 4, 2009. On December 10, 2009, the NMPRC issued a final order conditionally approving and clarifying the unopposed stipulation. The stipulated rates approved in the final order went into effect with January 2010 bills.
Investigation into Recovering County Franchise Fees. On December 10, 2009, the NMPRC issued an order in NMPRC Case No. 09-00421-UT, requiring the Company to show cause why it should collect franchise fees from its customers on behalf of Doña Ana and Otero Counties (the “Counties”). The Company responded to the order on January 5, 2010. On January 26, 2010, the NMPRC issued its decision concluding that the imposition of franchise fees by New Mexico counties is not authorized under New Mexico law and, therefore, the Company may not pass through to its customers some past and all ongoing franchise fees imposed by the Counties. The order concluded that only “home rule” municipalities, who had adopted a charter under the state constitution could impose franchise fees or taxes, provided the residents so voted.
As a result of its findings, the NMPRC directed the Company to immediately cease passing through to its customers any franchise fees paid by the Company to the Counties. The NMPRC also directed the Company to refund to its customers in the Counties the amount of franchise fees charged to those customers since June 1, 2004, plus interest. The Company estimates that its refund obligation under the order would be approximately $5.7 million, plus accrued interest of approximately $1.0 million through December 31, 2009. The order stated that the Company was required to refund these franchise fees to customers over a three-year period through a credit on customer bills and file tariffs for refunding within three days. On January 29, 2010, the NMPRC granted the Company’s request to extend its deadline for compliance with the order until February 12, 2010. Interest will continue to accrue on the unamortized balance until fully refunded. The order does not relieve the Company of its obligation to pay franchise fees to the Counties but states that this issue must be addressed by the New Mexico courts.
The Company immediately filed a Notice of Appeal with the New Mexico Supreme Court on January 27, 2010 (the “Appeal”), seeking to set aside the order on legal and jurisdictional grounds. The Company followed with a motion for Emergency Stay on January 29, 2010, asking the New Mexico Supreme Court to stay the order pending the Appeal. The Company also asked the NMPRC, on February 12, 2010, to delay implementation of its order pending the Appeal. The Counties moved to intervene in the Appeal on February 10, 2010, and have also informed the Company they intend to pursue their own legal actions opposing the order. The Company has placed any pending franchise payments to the Counties in escrow accounts pending resolution of the proceedings. On February 22, 2010, the New Mexico Supreme Court granted the Company’s motion for Emergency Stay pending the outcome of the Appeal and granted the Counties’ motion to intervene in the Appeal. The New Mexico legislature recently passed legislation that, if signed by the governor, could clarify the legality of the Company’s existing franchise agreement with the Counties. The Company cannot predict the outcome of the proceedings.
The Company will also review its legal options to terminate any future obligation to pay franchise fees to the Counties and to seek reimbursement from the Counties if refunds are ultimately required. The Company cannot predict the outcome of these legal reviews or any legal proceedings that may follow.
FPPCAC Rulemaking and Workshops. The NMPRC has docketed workshops (Case No. 07-00389-UT) to review consistency and potential changes to the FPPCAC rule in New Mexico. Comments have been filed by parties and workshops have been held for discussion and consideration of any changes to the existing FPPCAC rule that could be included in a new rulemaking proceeding. The NMPRC has no proposed rule revisions to date.
Pollution Control Bond Refunding. On March 20, 2008, the Company filed an application with the NMPRC requesting authority for long-term securities transactions necessary to refund and reissue certain Pollution Control Refunding Revenue Bonds (the “PCBs”). On April 22, 2008, the NMPRC issued a final order granting the Company the authority to enter into the securities transactions necessary to refund and reissue the Company’s Series B and Series C PCBs. On March 26, 2009, the Company completed a refunding transaction related to an aggregate principal amount of $100.6 million in pollution control indebtedness.
Notice of Investigation of Rates. On August 3, 2007, the Company received a “Notice of Investigation of Rates of El Paso Electric Company” from the NMPRC in Case No. 07-00317-UT. On August 21, 2007, the NMPRC requested that the Company file a response to the issues, including the reasonableness of fuel and purchased power costs. On September 7, 2007, the Company filed its response and requested that the NMPRC suspend its investigation and close the docket. No further action has been taken by the NMPRC and the docket is moot since the rates established in Case No. 07-00317-UT are no longer in effect.
New Mexico Investigation into Executive Compensation. In December 2007, the NMPRC initiated an investigation into executive compensation of investor-owned gas and electric public utilities. In its order initiating the investigation, the NMPRC required each utility to provide information on compensation of executive officers and directors for the period 1977-2006. The Company provided the requested information. No further action has been taken by the NMPRC.
2009 New Mexico Integrated Resource Plan Filing. On July 16, 2009, the Company submitted its initial Integrated Resource Plan (“IRP”) pursuant to the requirements of NMPRC Rule 17.7.3. The filing identifies the Company’s four-year action plan to meet resource needs based upon a twenty-year resource plan. The four-year action plan includes the addition of a natural gas-fired combustion turbine in 2012; a competitive-bid request for proposals to add a combined cycle plant in three phases in 2013, 2014, and 2016; evaluation of a direct load control project for possible integration in the resource plan; and a competitive-bid request for proposals to acquire additional wind and biomass renewable resources in 2013 and 2015 to comply with the New Mexico Renewable Portfolio Standard Requirements. The NMPRC accepted the proposed IRP as compliant with its rules without a hearing in August 2009.
2009 New Mexico Annual Renewable Procurement Plan Filing. On July 1, 2009, the Company filed its 2009 Annual Renewable Procurement Plan in compliance with the New Mexico Renewable Energy Act. The Company’s 2009 plan was designed to meet the full renewable portfolio standard (“RPS”) of 6 percent of New Mexico jurisdictional retail energy sales for 2010 and 10 percent beginning in 2011. The Company requested approval by the NMPRC of the following proposals: 1) to increase the solar resources used for RPS compliance pursuant to the long-term contract with New Mexico SunTower, LLC; 2) to pay an additional $0.015 per kWh for renewable energy credits (“RECs”) obtained from a biomass energy facility; and 3) to modify and expand the Company’s existing REC purchase program for customer-installed qualifying facilities up to 10 kW and to add a program for customer-installed qualifying facilities of 10 kW to 100 kW. Hearings were held on October 1, 2009. On December 22, 2009, the NMPRC issued its final order substantially approving the Company’s proposed procurement plan modified to increase the price paid for small, customer-owned solar generated energy from the proposed price of $0.10 per kWh to $0.12 per kWh.
Investigation into the Service Quality of El Paso Electric Company. On October 22, 2009, NMPRC Staff filed a petition requesting an investigation into the quality of service of the Company’s power distribution system in the Santa Teresa Industrial Park, based upon a report prepared for customers in that area by the Los Alamos National Laboratory. On October 27, 2009, the NMPRC decided to initiate an investigation and ordered the Company to respond no later than November 16, 2009. The Company filed an initial response on November 16, 2009 and a supplemental response on January 8, 2010 after obtaining data on which the report was based. The Company responses provided evidence that the reliability and power quality performance for the Company’s service territory as a whole and on the Santa Teresa circuits in particular meet all applicable reliability standards and comport with good utility practices. On January 28, 2010, the NMPRC Staff filed its reply stating that they found no factual basis to conclude that the Company has violated NMPRC rules by not following good utility practices regarding service quality to the customers in the Santa Teresa Industrial Park area and recommended the NMPRC dismiss this proceeding. The Company is unable at this time to predict the ultimate outcome of this docket.
Federal Regulatory Matters
Transmission Dispute with Tucson Electric Power Company (“TEP”). In January 2006, the Company filed a complaint with the FERC to interpret the terms of a Power Exchange and Transmission Agreement (the “Transmission Agreement”) entered into with TEP in 1982. TEP filed a complaint with the FERC one day later raising virtually identical issues. TEP claimed that, under the Transmission Agreement, it was entitled to up to 400 MW of firm transmission rights on the Company’s transmission system that would enable it to transmit power from the Luna Energy Facility (“LEF”) located near Deming, New Mexico to Springerville or Greenlee in 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 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, and hearings on the disputed issues were held before an administrative law judge. In the initial decision dated September 6, 2007, the administrative law judge found that the Transmission Agreement allows TEP to transmit power from the LEF to Arizona but limits that transmission to 200 MW on any segment of the circuit and to non-firm service on the segment from Luna to Greenlee. The Company and TEP filed exceptions to the initial decision.
On November 13, 2008, the FERC issued an order on the initial decision finding that the transmission rights given to TEP in the Transmission Agreement are firm and are not restricted for transmission of power from Springerville as the receipt point to Greenlee as the delivery point. Therefore, pursuant to the order, TEP can use its transmission rights granted under the Transmission Agreement to transmit power from the LEF to either Springerville or Greenlee so long as it transmits no more than 200 MW over all segments at any one time. The FERC also ordered that the Company refund to TEP all sums with interest that TEP had paid it for transmission under the applicable transmission service agreements since February 2006 for service relating to the LEF. On December 3, 2008 the Company refunded $9.7 million to TEP. The Company had established a reserve for the rate refund of approximately $7.2 million as of September 30, 2008, resulting in a pre-tax charge to earnings of
approximately $2.5 million in 2008. The Company also paid TEP interest on the refunded balance of approximately $0.9 million, which was also charged to earnings in 2008. The Company filed a request for rehearing of the FERC’s decision on December 15, 2008, seeking reversal of the order on the merits and a return of any refunds made in the interim, as well as compensation for all service that the Company may provide to TEP from the LEF over the Company’s transmission system on a going forward basis. The FERC suspended the period for ruling on the motion for rehearing on January 14, 2009. If the FERC denies the Company’s request for rehearing or again finds against the Company on rehearing, the Company will have the right to seek judicial review of the order. If the order is not reversed, the Company will lose the opportunity to receive compensation from TEP for such transmission service in the future. The Company cannot predict the outcome of such potential future proceedings.
In an ancillary proceeding, TEP filed a lawsuit in the United States District Court for the District of Arizona in December 2008, seeking reimbursement for amounts TEP paid a third party transmission provider for purchases of transmission capacity between April 2006 and May 2007, allegedly totaling approximately $1.5 million, plus accrued interest. TEP alleges that the Company was obligated to provide TEP with that transmission capacity without charge under the Transmission Agreement. In September 2009, the Court granted a stay in this suit pending a resolution of the underlying FERC proceeding and any appeal thereof. The Company cannot predict the outcome of this matter.
Pollution Control Bond Refunding. On April 4, 2008, the Company filed an application with the FERC requesting authority for long-term securities transactions necessary to refund and reissue the Company’s Series B and Series C PCBs. The FERC issued an order on May 1, 2008, granting authority for the securities transactions. On March 26, 2009, the Company completed a refunding transaction related to an aggregate principal amount of $100.6 million in pollution control indebtedness. See Note H of the Notes to the Consolidated Financial Statements.
RTOs. FERC’s rule on RTOs (“Order 2000”) strongly encourages, but does not require, public utilities to form and join regional transmission organizations (“RTOs”). The Company is an active participant in the development of WestConnect. The Company has entered into a memorandum of understanding with thirteen other transmission owners that obligates the parties to participate in and commit resources to ongoing joint efforts, including involvement with stakeholders, customers, local, state and federal regulatory personnel, and other western grid transmission providers to identify, develop and implement cost-effective wholesale market enhancements on a voluntary, phased-in basis to add value in transmission accessibility, wholesale market efficiency and reliability for wholesale users of the western grid. These enhancements may ultimately include formation of an RTO. WestConnect will continue to work with the FERC and two other proposed RTOs in the west to achieve a seamless market structure. The Company comprises approximately 6% of WestConnect and cannot control the terms or timing of its development. WestConnect as an RTO will not be operational for several years, if it is achieved at all.
On February 10, 2009, the FERC accepted a participation agreement submitted by nine WestConnect participants establishing the WestConnect Point-to-Point Regional Transmission Service Experiment (the “Proposal”). The FERC also conditionally accepted (subject to the participants making minor compliance filings) associated regional transmission tariffs that implement the Proposal for a two-year period. The Proposal calls for participants to offer customers the option of buying hourly non-firm, point-to-point transmission service across their collective transmission systems at a single rate. Taking coordinated service under the proposal is an alternative to pancaked point-to-point transmission
service offered under each member’s individual Open Access Transmission Tariff. Participation in the Proposal has not had a material impact on transmission revenues.
Department of Energy. The DOE regulates the Company’s exports of power to the Comisión Federal de Electricidad 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. See “Facilities - Palo Verde Station” for discussion regarding application to extend the Palo Verde licenses for 20 years.
Sales for Resale
The Company entered into a contract on April 18, 2007, as amended on August 29, 2008, March 31, 2009 and May 8, 2009, to sell up to 100 MW of firm energy and 50 MW of contingent energy to Imperial Irrigation District (“IID”) beginning May 1, 2007, and continuing through October 31, 2009. The contract also provides for the Company to sell up to 100 MW firm energy and 40 MW of contingent energy beginning November 1, 2009 through April 30, 2010. To ensure that power is available to meet the IID contract demand, the Company entered into a contract effective May 1, 2007, as amended and restated on September 3, 2008 and March 30, 2009, to purchase up to 100 MW of firm energy from Credit Suisse Energy, LLC. This contract provides for up to 100 MW of firm energy to be delivered at Palo Verde through April 30, 2010, and 50 MW of energy delivered at Four Corners in the months of July through September 2007 and May through September for the years 2008 through 2010.
The Company provides firm capacity and associated energy to the RGEC pursuant to an ongoing contract which requires a two-year notice to terminate. The Company also provides network integrated transmission service to RGEC pursuant to the Company’s Open Access Transmission Tariff (“OATT”). In 2006, the Company provided RGEC with a notice of termination. On March 28, 2008, the Company filed with FERC a power sales agreement for full requirements wholesale electric service (the “Agreement”) to sell capacity and energy to RGEC at a cost-based formula rate. The Company requested that the Agreement become effective April 1, 2008 to replace the power sales agreement that expired March 31, 2008. The Agreement includes a formula-based rate that will be updated annually to recover non-fuel generation costs and a fuel adjustment clause designed to recover all eligible fuel and purchased power costs allocable to RGEC. An order accepting the tariff was issued on May 21, 2008 approving the effective date of April 1, 2008.
Power Sales Contracts
The Company has entered into several short-term (three months or less) off-system sales contracts for the first quarter of 2010. The Company has also entered into other longer-term sales for which the supply is fully hedged.
Franchises and Significant Customers
El Paso Franchise
The Company has a franchise agreement with El Paso, the largest city it serves, through July 31, 2030. The franchise agreement includes a franchise fee of 3.25% of revenues and allows the Company to utilize public rights-of-way necessary to serve its retail customers within El Paso.
Las Cruces Franchise
In February 2000, the Company and Las Cruces entered into a seven-year franchise agreement with a franchise fee of 2% of revenues for the provision of electric distribution service. Las Cruces exercised its right to extend the franchise for an additional two-year term which ended April 30, 2009 and waived its option to purchase the Company’s distribution system pursuant to the terms of the February 2000 settlement agreement. The Company is currently operating under an implied franchise by satisfying all obligations from the expired franchise.
Military Installations
The Company currently serves Holloman Air Force Base (“Holloman”), White Sands Missile Range (“White Sands”) and Fort Bliss. The Company’s sales to the military bases represent approximately 3% of annual operating revenues. The Company signed a contract with Ft. Bliss in October 2008 under which Ft. Bliss takes retail electric service from the Company. The contract is effective until the later of: (i) August 1, 2010 or (ii) new base rates have been approved for the Company in any Texas rate proceeding. In April 1999, the Army and the Company entered into a ten-year contract to provide retail electric service to White Sands. The contract with White Sands expired in 2009 and the Company is serving White Sands under the applicable New Mexico tariffs. In March 2006, the Company signed a contract with Holloman that provides for the Company to provide retail electric service and limited wheeling services to Holloman for a ten-year term which expires in January 2016.
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, and the decisions of regulatory agencies. Our common stock price and creditworthiness will be affected by local, regional and national macroeconomic trends, general market conditions and the expectations of the investment community, all of which are largely beyond our control. In addition, the following statements highlight risk factors that may affect our consolidated financial condition and results of operations. These are not intended to be an exhaustive discussion of all such risks, and the statements below must be read together with factors discussed elsewhere in this document and in our other filings with the SEC.
Our Revenues and Profitability Depend upon Regulated Rates
Our retail rates are subject to regulation by incorporated municipalities in Texas, the PUCT, the NMPRC and the FERC. The Texas Rate Agreements, which established our current retail base rates in Texas, expire on June 30, 2010. We filed a general base rate case in Texas in December 2009 seeking a rate increase. In addition, the recently settled NMPRC Case No. 09-00171-UT established rates that became effective January 2010. It is anticipated, however, that we will need to file another general base rate case in New Mexico in 2010 seeking an additional rate increase to incorporate the construction costs of Phase 2 of Newman Unit 5 into rate base.
Our profitability depends on our ability to recover the costs, including a reasonable return on invested capital, of providing electric service to our customers through base rates approved by our regulators. These rates are generally established based on an analysis of the expenses we incur in an historical test year, and as a result, the rates ultimately approved by our regulators may or may not match our expenses at any given time. Rates in New Mexico may be established using projected costs and investment for a future test year period in certain instances. While rate regulation is based on the assumption that we will have a reasonable opportunity to recover our costs and earn a reasonable rate of return on our invested capital, there can be no assurance that our current Texas rate case or our anticipated New Mexico rate case in 2010 will result in base rates that will allow us fully to recover our costs including a reasonable return on invested capital. There can be no assurance that our regulators will determine that all of our costs are reasonable and have been prudently incurred. It is also likely that third parties will intervene in our rate cases and challenge whether our costs are reasonable and necessary. If all of our costs are not recovered through the retail base rates ultimately approved by our regulators, our profitability and cash flow could be adversely affected which, over time, could adversely affect our ability to meet our financial obligations.
We May Not Be Able To Recover All Costs of New Generation
We have completed Phase 1, consisting of two 70 MW gas turbine generators, in the construction of Newman Unit 5 in El Paso to meet our expected customer demand for electricity. We have risks associated with completing the construction of Newman Unit 5 on time and within projected costs. We have issued new debt to help fund the construction of Newman Unit 5; however, we have risks associated with obtaining additional financing for Newman Unit 5 at reasonable rates as we expect to issue additional debt to finance the completion of the plant and other capital expenditures.
The cost of financing and constructing Newman Unit 5 will be reviewed in future rate cases in both Texas and New Mexico. To the extent that the PUCT or NMPRC determines that the costs of construction are not reasonable because of cost overruns, delays or other reasons, we may not be allowed to recover these costs from customers in base rates.
In addition, if Newman Unit 5 is not completed on time, we may be required to purchase power or operate less efficient generating units to meet customer requirements. Any replacement purchased power or fuel costs will be subject to regulatory review by the PUCT and NMPRC. We face financial risks to the extent that recovery is not allowed for any replacement fuel costs resulting from delays in the completion of Newman Unit 5.
Turmoil in the Credit Markets and Economic Downturn
The global credit and equity markets and the overall economy have been through a state of turmoil and have not fully recovered. These events could have a number of effects on our operations and our capital programs. For example, tight credit and capital markets could make it difficult and more expensive to raise capital to fund our operations and capital programs. If we are unable to access the credit markets, we could be required to defer or eliminate important capital projects in the future. In addition, declines in the stock market have reduced and may further reduce the value of our financial assets and decommissioning trust investments and negatively impact our future earnings and cash flow. Such market declines may also increase our funding obligations for our pension plans, other post-retirement benefit plans and nuclear decommissioning trusts. Changes in the corporate interest rates which we use as the discount rate to determine our pension and other post-retirement liabilities may have an impact on our funding obligations for such plans and trusts. Further, the weak economy may result in reduced customer demand, both in the retail and wholesale markets, and increases in customer delinquencies and write-offs. We experienced a significant decline in electric usage by our large industrial customers in 2009. This decline in large industrial customer usage could continue and we could see similar impacts on usage of other customers resulting in a decrease in earnings in 2010. The credit markets and overall economy may also adversely impact the financial health of our suppliers. If that were to occur, our access to and prices for inventory, supplies and capital equipment could be adversely affected. Our power trading counterparties could also be adversely impacted by the market and economic conditions which could result in reduced wholesale power sales or increased counterparty credit risk. This is not intended to be an exhaustive list of possible effects, and we may be adversely impacted in other ways.
Our Costs Could Increase or We Could Experience Reduced Revenues if
There are Problems at the Palo Verde Nuclear Generating Station
A significant percentage of our generating capacity, off-system sales margins, assets and operating expenses is attributable to Palo Verde. Our 15.8% interest in each of the three Palo Verde units totals approximately 633 MW of generating capacity. Palo Verde represents approximately 39% of our available net generating capacity and provided approximately 45% of our energy requirements for the twelve months ended December 31, 2009. Palo Verde comprises approximately 37% of our total net plant-in-service and Palo Verde expenses comprise a significant portion of operation and maintenance expenses. APS is the operating agent for Palo Verde, and we have limited ability under the ANPP Participation Agreement to influence operations and costs at Palo Verde. Palo Verde operated at a capacity factor of 88.9% and 84.4% in the twelve months ended December 31, 2009 and 2008, respectively.
Our ability to increase retail base rates in Texas and New Mexico is limited and we cannot assure that revenues will be sufficient to recover any increased costs, including any increased costs in connection with Palo Verde or other operations, whether as a result of inflation, changes in tax laws or regulatory requirements, or other causes.
We May Not Be Able to Recover All of Our Fuel Expenses from Customers
In general, by law, we are entitled to recover our prudently incurred fuel and purchased power expenses from our customers in Texas and New Mexico. NMPRC Case No. 09-00171-UT provides for energy delivered to New Mexico customers from the deregulated Palo Verde Unit 3 to be recovered through fuel and purchased power costs based upon an existing purchased power contract with Credit Suisse Energy, LLC. Fuel and purchased power expenses in New Mexico and Texas are subject to reconciliation by the PUCT and the NMPRC. Prior to the completion of a reconciliation, we record fuel and purchased power costs such that fuel revenues equal recoverable fuel and purchased power expense including the repriced energy costs for Palo Verde Unit 3 in New Mexico. In the event that a disallowance occurs during a reconciliation proceeding, the amounts recorded for fuel and purchased power expenses could differ from the amounts we are allowed to collect from our customers, and we would incur a loss to the extent of the disallowance.
In New Mexico, the FPPCAC allows us to reflect current fuel and purchased power expenses in the FPPCAC and to adjust for under-recoveries and over-recoveries with a two-month lag. In Texas, fuel costs are recovered through a fixed fuel factor that may be adjusted three times per year. If we materially under-recover fuel costs, we may seek a surcharge to recover those costs at any time the balance exceeds a threshold material amount and is expected to continue to be materially under-recovered. During periods of significant increases in natural gas prices such as occurred in the first eight months of 2008, 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, 2009 and December 31, 2008, the Company had a net over-collection balance of $18.0 million and a net under-collection balance of $46.9 million, respectively. To the extent the fuel and purchased power recovery processes in Texas and New Mexico do not provide for the timely recovery of such costs, we could experience a material negative impact on our cash flow.
Equipment Failures and Other External Factors Can Adversely Affect Our Results
The generation and transmission of electricity require the use of expensive and complex equipment. While we have a maintenance program in place, generating plants are subject to unplanned outages because of equipment failure. We are particularly vulnerable to this due to the advanced age of several of our gas-fired generating units in or near El Paso. In addition, we are seeking to extend the lives of these plants. In the event of unplanned outages, we must acquire power from others at unpredictable costs in order to supply our customers and comply with our contractual agreements. This can materially increase our costs and prevent us from selling excess power at wholesale, thus reducing our profits. In addition, actions of other utilities may adversely affect our ability to use transmission lines to deliver or import power, thus subjecting us to unexpected expenses or to the cost and uncertainty of public policy initiatives. We are particularly vulnerable to this because a significant portion of our available energy (at Palo Verde and Four Corners) is located hundreds of miles from El Paso and Las Cruces and must be delivered to our customers over long distance transmission lines. In addition, Palo 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.
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, alternative sources of power, including co-generation of electric power. Deregulation legislation is in effect in Texas requiring us to separate our transmission and distribution functions, which would remain regulated, from our power generation and energy services businesses, which would operate in a competitive market, in the future. In 2004, the PUCT 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, if they are achieved at all. 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.
Furthermore, in an order dated December 17, 2009, the NMPRC concluded that certain third party developers who own renewable generation which is installed on utility customers’ premises to supply one or more customers with a portion of their electricity needs, payments for which are based on a kW charge, are not public utilities subject to regulation by the NMPRC. The New Mexico legislature recently passed legislation which, if signed by the governor, would establish the circumstances under which certain third-party suppliers would be permitted to compete with the Company on a limited basis beginning in January 2011. If this order survives an appeal filed by us and other public utilities or if the legislation is signed by the governor and becomes law, we may face competition from these third party developers in New Mexico. There can be no assurance that such competition would not adversely affect our future operations, cash flow and financial condition.
Climate Change and Related Legislation and Regulatory Initiatives Could Affect Demand for
Electricity or Availability of Resources, and Could Result in Increased Compliance Costs
The U.S. Congress is considering new legislation to restrict or regulate greenhouse gas emissions. For example, the American Clean Energy and Security Act of 2009, which was passed by the U.S. House of Representatives in 2009, could, if enacted by the full Congress, require greenhouse gas emissions reductions by covered sources of as much as 17% from 2005 levels by 2020 and by as much as 83% by 2050. In addition, almost half of the states, either individually or through multi-state regional initiatives, have begun to address greenhouse gas emissions, primarily through the planned development of emission inventories or regional greenhouse gas cap and trade programs. The State of New Mexico, where we operate one facility and have an interest in another facility, has joined with California and several other states in the Western Regional Climate Action Initiative and is pursuing a rulemaking which would be more restrictive than the legislation pending in Congress to reduce greenhouse gas emissions in the state. Also, as a result of the U.S. Supreme Court’s decision on April 2, 2007 in Massachusetts, et al. v. EPA, the EPA may regulate greenhouse gas emissions even if Congress does not adopt new legislation specifically addressing emissions of greenhouse gases.
It is not currently possible to predict how any such proposed or future greenhouse gas legislation by Congress, the states or multi-state regions or any such regulations adopted by the EPA or state
environmental agencies will impact our business. However, any such legislation or regulation of greenhouse gas emissions or any future related litigation could result in increased compliance costs or additional operating restrictions or increased or reduced demand for our services, could require us to purchase rights to emit greenhouse gases, and could have a material adverse effect on our business, financial condition, reputation or results of operations.
Climate change also has potential physical effects that could be relevant to the Company’s business. In particular, some studies suggest that climate change could affect our service area by causing higher temperatures, less winter precipitation and less spring runoff, as well as by causing more extreme weather events. Such developments could change the demand for power in the region and could also impact the price or ready availability of water supplies and affect maintenance needs and the reliability of Company equipment. Given the very significant remaining uncertainties regarding whether and how these issues will be regulated, as well as the timing and severity of any physical effects of climate change, we believe it is impossible at present to meaningfully quantify the costs of these potential impacts.
Item 1B.
Item 1B. Unresolved Staff Comments
None.
Executive Officers of the Registrant
The executive officers of the Company as of February 15, 2010, were as follows:
Name
Age
Current Position and Business Experience
David W. Stevens
Chief Executive Officer since November 2008; Principal of Professional Consulting Services, LLC from December 2007 to November 2008; President, Chief Executive Officer and Board Member for Cascade Natural Gas Corporation from April 2005 to July 2007; President and Chief Operating Officer for Panhandle Energy from July 2003 to April 2005.
J. Frank Bates
President since October 2009; President and Chief Operating Officer from November 2008 to October 2009; Interim President and Chief Executive Officer from February 2008 to November 2008; Executive Vice President and Chief Operating Officer from May 2005 to February 2008; Executive Vice President and Chief Operations Officer from November 2001 to May 2005.
David G. Carpenter
Senior Vice President and Chief Financial Officer since August 2009; Vice President - Regulatory Services and Controller from September 2008 to August 2009; Vice President - Corporate Planning and Controller from August 2005 to September 2008; Director - Texas Regulatory Services for American Electric Power Services Corporation from June 2000 to August 2005.
Richard G. Fleager
Senior Vice President - Customer Care and External Affairs since April 2009; Vice President for Texas Gas Service from September 1997 to March 2009.
Rocky R. Miracle
Senior Vice President - Corporate Planning and Development since August 2009; Vice President - Corporate Planning from September 2008 to August 2009; Director of Business Operations Support - Texas Operations for American Electric Power Services Corporation from August 2004 to August 2008.
George A. Williams
Senior Vice President and Chief Operating Officer since October 2009; Senior Vice President-Operations for Commonwealth Edison from August 2006 to September 2009; Vice President - Operations Grand Gulf Nuclear Operation Station for Entergy Nuclear South from April 2003 to August 2006.
Steven T. Buraczyk
Vice President - Power Marketing and Fuels since July 2008; Director of Power Marketing and Fuels from August 2006 to August 2008; Manager of Power Marketing from August 2004 to August 2006.
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.
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.
Nathan T. Hirshi
Vice President - Special Projects since December 2009; Partner - Assurance for KPMG LLP from January 2005 to April 2009.
Mary E. Kipp
Vice President - Legal and Chief Compliance Officer since December 2009; Assistant General Counsel and Director of FERC Compliance from December 2007 to December 2009; Senior Enforcement Attorney - FERC from January 2004 to December 2007.
Kerry B. Lore
Vice President - Customer Care since December 2008; Vice President - Administration from May 2003 to December 2008.
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 R. 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.
Guillermo Silva, Jr.
Corporate Secretary since February 2006; Vice President - Information Services from February 2003 to February 2006.
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.
The executive officers of the Company are elected annually and serve at the discretion of the Board of Directors.
Item 2.
Item 2. Properties
The principal properties of the Company are described in Item 1, “Business,” and such descriptions are incorporated herein by reference. Transmission lines are located either on private rights-of-way, easements, or on streets or highways by public consent.
In February 2008, the Company purchased the executive and administrative office building in El Paso that it had previously leased. All obligations incurred under this lease were terminated. In June 2008, the Company entered into an agreement to lease land in El Paso adjacent to the Newman Power Station under a lease which expires in June 2033 with a renewal option of 25 years.
In addition, the Company leases certain warehouse facilities in El Paso under a lease which expires in December 2014. The Company also has several other leases for office and parking facilities which expire within the next five 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.
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 2009.
PART II
Item 5.
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
The Company’s common stock trades on the New York Stock Exchange (“NYSE”) 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:
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, 2004 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, 2010, there were 3,574 holders of record of the Company’s common stock. The Company does not currently pay dividends on its common stock. The Company currently plans to continue its stock repurchase programs with the goal of managing its capital structure and enhancing shareholder value.
Since the inception of the stock repurchase programs in 1999, the Company has repurchased a total of approximately 21.1 million shares of its common stock at an aggregate cost of $303.4 million, including commissions. In November 2007, the Board authorized the repurchase of up to 2 million shares of the Company’s outstanding common stock (the “2007 Plan”). During 2009, the Company repurchased 1,320,384 shares of common stock at an aggregate cost of $24.1 million, including 569,149 shares repurchased in the fourth quarter at an aggregate cost of $11.2 million. The table below provides the amount of the fourth quarter repurchases on a monthly basis.
As of December 31, 2009, 200,982 shares remain authorized to be repurchased under the 2007 Plan. On February 19, 2010, the Board authorized an additional repurchase of up to 2 million shares of the Company’s outstanding common stock. The Company may in the future make purchases of its common stock pursuant to the authorized plans in open market transactions at prevailing prices and may engage in private transactions where appropriate. The repurchased shares will be available for issuance under employee benefit and stock incentive plans, or may be retired.
For Equity Compensation Plan Information see Part III, Item 12 - Security Ownership of Certain Beneficial Owners and Management.
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 periods related to basic and diluted earnings per share and weighted average number of shares and dilutive potential shares outstanding have been revised to conform with 2009 FASB guidance as discussed in Note F of the Notes to the Consolidated 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
Our consolidated financial statements have been prepared in conformity with GAAP. Note A to the consolidated financial statements contains a summary of our significant accounting policies, many of which require the use of estimates and assumptions. We believe that of our significant accounting policies, the following are noteworthy because they are based on estimates and assumptions that require complex, subjective assumptions by management, which can materially impact reported results. Changes in these estimates or assumptions, or actual results that are different, could materially impact our financial condition and results of operation.
Regulatory Accounting
We apply accounting standards that recognize the economic effects of rate regulation in our Texas, New Mexico and FERC jurisdictions. As a result, we record certain costs or obligations as either assets or liabilities on our balance sheet and amortize them in subsequent periods as they are reflected in regulated rates. The deferral of costs as regulatory assets is appropriate only when the future recovery of such costs is probable. In assessing probability, we consider such factors as specific regulatory orders, regulatory precedent and the current regulatory environment. As of December 31, 2009, we had recorded regulatory assets currently subject to recovery in future prices of approximately $60.7 million and regulatory liabilities of approximately $14.1 million as discussed in greater detail in Note C of the Notes to the Consolidated Financial Statements. In the event we determine that we can no longer apply the FASB guidance for regulated operations to all or a portion of our operations, 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.
Collection of Fuel Expense
In general, by law and regulation, our actual fuel and purchased power expenses are recovered from our customers. In times of rising fuel prices, we experience a lag in recovery of higher fuel costs. These costs are subject to reconciliation by the PUCT and the NMPRC. Prior to the completion of a reconciliation proceeding, we record fuel transactions such that fuel revenues, including fuel costs recovered through base rates in New Mexico, equal fuel expense except for the fixed portion in New Mexico prior to July 2007. In the event that a disallowance of fuel cost recovery 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. The determination of the estimated liability requires the use of various assumptions pertaining to decommissioning costs, escalation and discount rates. We determine how we will fund our share of those
estimated costs by making assumptions about future investment returns and future decommissioning cost escalations. Decommissioning costs will be adjusted prospectively for future changes in estimated decommissioning costs and when actual costs are incurred to decommission the plant. Further, if the rates of return earned by the trusts fail to meet expectations or estimated costs to decommission the plant increase, we could be required to increase our funding to the decommissioning trust accounts. Historically, we have been permitted to collect in rates in Texas and New Mexico the costs of nuclear decommissioning.
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 rates, expected return on plan assets, rate of compensation increase, life expectancy of retirees and health care cost inflation. 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.
Tax Accruals
We use the asset and liability method of accounting for income taxes. Under this method, we recognize deferred tax assets and liabilities for the future tax consequences attributable to temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities. The application of income tax law and regulations is complex and we must make judgments regarding income tax exposures. Changes in these judgments, due to changes in law, regulation, interpretation, or audit adjustments can materially affect amounts we recognize in our consolidated financial statements.
Overview
The following is an overview of our results of operations for the years ended December 31, 2009, 2008 and 2007. Income for the years ended December 31, 2009, 2008 and 2007 is shown below:
The following table and accompanying explanations show the primary factors affecting the after-tax change in income before extraordinary item between the calendar years ended 2009 and 2008, 2008 and 2007, and 2007 and 2006 (in thousands):
(a) Retail non-fuel base revenues increased in 2009 compared to 2008 primarily due to increased kWh sales to residential customers and public authorities partially offset by a decrease in kWh sales to large commercial and industrial customers. Retail non-fuel base revenues exclude fuel recovered through New Mexico base rates.
(b) Retail non-fuel base revenues increased in 2008 compared to 2007 largely due to increased kWh sales to small commercial and industrial customers and public authorities.
(c) Retail non-fuel base revenues increased in 2007 compared to 2006 primarily due to increased kWh sales reflecting growth in the number of customers served.
(d) Transmission wheeling for 2009 increased due to the reversal of $2.5 million of 2006 wheeling revenues from Tucson Electric Power pursuant to an order of the FERC in 2008.
(e) Transmission wheeling for 2008 increased largely due to wheeling power in southern New Mexico and Arizona partially offset by the reversal of $2.5 million of 2006 wheeling revenues from Tucson Electric Power pursuant to an order of the FERC.
(f) In 2008 operation and maintenance costs increased at our fossil-fueled generating plants as planned major maintenance was performed at Newman Unit 3 and Four Corners Unit 5. In 2007 no major maintenance was performed at our fossil-fueled generating units.
(g) AFUDC (allowance for funds used during construction) increased for 2008 and 2007 due to increased construction work in progress subject to AFUDC. Capitalized interest increased for 2008 and 2007 due to increased nuclear fuel balances subject to capitalized interest.
(h) AFUDC also increased for 2007 compared to 2006 due to the re-application of SFAS No. 71 to our Texas jurisdiction beginning December 31, 2006.
(i) Depreciation and amortization expense increased due to increased plant balances including the replacement of Palo Verde Unit 3 steam generators in January 2008.
(j) Lower investment and interest income in 2008 compared to 2007 is primarily due to impairments of equity securities in our Palo Verde decommissioning trust funds and a decrease in the fair value of our investments in auction rate securities.
(k) Lower retained margins on off-system sales in 2009 compared to 2008 are primarily the result of reduced margins per MWh due to lower market prices and a decline in MWh sales.
(l) Higher retained margins on off-system sales are primarily the result of increased sales and margins from off-system sales to a wholesale customer.
(m) Deregulated Palo Verde Unit 3 proxy market pricing reflects lower proxy market prices and lower sales of the deregulated portion of Palo Verde Unit 3 to retail customers due mostly to its planned refueling outage in April and May 2009.
(n) In 2008, deregulated Palo Verde Unit 3 proxy market pricing reflects higher proxy market prices and increased sales of the deregulated portion of Palo Verde Unit 3 to retail customers when compared to 2007 as the unit did not operate in the fourth quarter of 2007 due to its refueling and replacement of steam generators.
(o) Administrative and general expenses increased in 2009 compared to 2008 primarily due to increased accruals for employee incentive compensation and increased pension and benefits expenses reflecting a lower discount rate used to determine postretirement benefit costs.
(p) Administrative and general expenses decreased in 2008 compared to 2007 primarily due to lower pension and other post-retirement benefits expenses reflecting an increase in the discount rate for the associated liabilities.
(q) Administrative and general expenses decreased in 2007 compared to 2006 due to an increase in capitalized employee salaries and benefits, decreased workers compensation insurance expense, and a sales tax refund.
(r) Palo Verde non-fuel operations and maintenance expense increased for 2009 compared to 2008 due to increased employee benefit expense and increased operating costs, partially offset by decreased maintenance costs in 2009.
(s) Palo Verde non-fuel operations and maintenance expenses increased due to increased operating costs at all three units in 2008 and higher maintenance costs during refueling outages in 2008 than during refueling outages during 2007.
(t) Palo Verde non-fuel operations and maintenance expenses increased for 2007 compared to 2006 due to higher maintenance costs at Palo Verde Unit 3 associated with the steam generator replacement and refueling in the fourth quarter of 2007, the higher maintenance costs at Unit 1 associated with refueling that unit in 2007 and higher operating costs at all three units.
(u) Interest expense on long-term debt increased for 2009 compared to 2008 and 2008 compared to 2007 due to the issuance of $150 million of 7.5% Senior Notes in June 2008 and higher interest rates on auction rate pollution control bonds in 2008.
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 rate agreements in Texas and New Mexico, we share 25% of our off-system sales margins with customers in Texas and New Mexico (effective July 1, 2005 and July 1, 2007, respectively). We are also sharing 25% of our off-system sales margins with our sales for resale customer under the terms of a contract which was effective April 1, 2008. In July 2010, off-system sales margins shared with customers increases to 90%.
Revenues from the sale of electricity include fuel costs that are recovered from our customers through fuel adjustment mechanisms. A significant portion of fuel costs are also recovered through base rates in New Mexico. We record deferred fuel revenues for the difference between actual fuel costs and recoverable fuel revenues until such amounts are collected from or refunded to customers. “Non-fuel base revenues” refers to our revenues from the sale of electricity excluding such fuel costs.
Retail non-fuel base revenue percentages by customer class are presented below:
No retail customer accounted for more than 2% of our non-fuel base revenues during such periods. As shown in the table above, residential and small commercial customers comprise more than 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 kWh sales and revenues during the summer
cooling season. The following table sets forth the percentage of our retail non-fuel base revenues derived during each quarter for the periods presented:
Heating and cooling degree days can be used to evaluate the effect of weather on energy use. For each degree the average outdoor temperature varies from a standard of 65 degrees Fahrenheit a degree day is recorded. The table below shows heating and cooling degree days compared to a 10-year average for 2009, 2008 and 2007.
Customer growth is a key driver in the growth of retail sales. The average number of retail customers grew 1.7% and 1.9% in 2009 and 2008, respectively. See the tables presented on pages 45 and 46 which provide detail on the average number of retail customers and the related revenues and kWh sales.
Retail non-fuel base revenues. Retail non-fuel base revenues increased by $13.2 million or 2.8% for the twelve months ended December 31, 2009 when compared to the same period in 2008 as a result of an increase of 6.0% in kWh sales to residential customers and a 2.3% increase in kWh sales to public authorities. Residential sales increased as a result of hotter summer weather in 2009 compared to 2008 and growth of 1.8% in the average number of residential customers served. Cooling degree days in 2009 were 23% higher than in 2008 and 8% above the 10-year average. Sales to other public authorities reflect increased sales to military bases. These increases were partially offset by a recession-related decline in sales to large commercial and industrial customers. Revenues from large commercial and industrial customers decreased 4.2% in the twelve months ended December 31, 2009 compared to the same period in 2008.
Retail non-fuel base revenues increased by $5.6 million or 1.2% for the twelve months ended December 31, 2008 when compared to the same period in 2007 primarily as a result of a 1.9% increase in the average number of customers served partially offset by declines in weather-related sales and sales to large commercial and industrial customers. During the twelve months ended December 31, 2008, retail kWh sales to residential customers were restrained by cooler than normal summer weather and warmer than normal winter weather. Cooling degree days in the twelve months ended December 31, 2008 were 10% lower and heating degree days were 5% lower than in the twelve months ended December 31, 2007. Non-fuel base revenues for residential customers increased $0.2 million, or 0.1%. Non-fuel base revenues for small commercial and industrial customers increased $6.5 million, or 3.9% while kWh sales grew 1.8% compared to the same period in 2007 reflecting a 4.6% increase in the average number of customers served. Non-fuel base revenues for public authority customers increased $1.7 million, or 2.3%
primarily as a result of increased sales to military bases and colleges and universities. Non-fuel base rate revenues to small commercial and industrial customers and other public authority customers also increased due to a full year of the base rate increase in New Mexico which became effective in July 2007. Non-fuel base revenues from large commercial and industrial customers decreased $2.8 million, or 7.1% due to the decrease in kWh sales to several large commercial and industrial customers and the loss of several of these customers reflecting the impact of the economic downturn in our service territory.
Fuel revenues. Fuel revenues consist of: (i) revenues collected from customers under fuel recovery mechanisms approved by the state commissions and the FERC, (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 and with our sales for resale customer, the fuel adjustment clause allows us to recover under-recoveries or refund over-recoveries of current fuel costs above the amount recovered in base rates with a two-month lag. Until terminated on July 1, 2007, a fixed amount of fuel costs was reflected in the New Mexico fuel adjustment clause for 10% of kWh sales. In Texas, fuel costs are recovered through a fixed fuel factor that may be adjusted up to three times per year. In addition, if we materially over-recover fuel costs, we must seek to refund the over-recovery, and if we materially under-recover fuel costs, we may seek a surcharge to recover those costs.
Natural gas prices have decreased significantly since August 2008 resulting in decreases in fuel costs and purchased power costs. As a result, we over-collected fuel costs for all three jurisdictions by $66.6 million in the twelve months ended December 31, 2009 compared to an under-recovery of fuel costs of $42.8 million in the twelve months ended December 31, 2008. In 2008, we implemented two fuel surcharges in Texas to collect fuel under-recovery balances. Both of these surcharges were terminated effective with May 2009 billings. In addition, in July 2009, we received approval from the PUCT to reduce our fixed fuel factor in Texas effective in August 2009 and in October 2009 we received approval from the PUCT to refund fuel over recoveries through August 2009 of $16.8 million and interest to customers in November and December 2009. At December 31, 2009, we had a fuel over-recovery balance of $18.0 million, including a $15.7 million over-recovery in Texas, a $2.2 million over-recovery in New Mexico, and a $0.1 million over-recovery from our FERC customer. In January 2010, we received approval in Texas for an interim refund of fuel over-recoveries incurred through November 2009 of $11.8 million with interest to be refunded to customers in February 2010. Over-recoveries in New Mexico and from our FERC customer will be refunded through fuel adjustment clauses during 2010.
Deferred fuel revenues in Texas increased substantially during the first eight months of 2008, until the increase in fuel costs was reflected in the fixed fuel factor effective in October 2008. We implemented two fuel surcharges in 2008 to collect deferred fuel under-recoveries in Texas. In May 2008, we implemented a 12-month surcharge of approximately $30.1 million, including interest. In October 2008, we implemented an 18-month surcharge of approximately $39.5 million including interest. During 2008 deferred fuel revenues in New Mexico increased due to the decision to defer recovery of a portion of New Mexico fuel under-collections until October 2008, after the summer cooling season, to reduce the impact on our customers. In September 2007, we completed the recovery of $53.6 million of fuel under-recoveries through a fuel surcharge from our Texas customers which began in October 2005. We completed the recovery in January 2007 of $34 million of fuel under-recoveries, including interest through the surcharge period, through a fuel surcharge which began in February 2006. In 2008 and 2007, we collected $26.0 million and $22.9 million of deferred fuel revenues in Texas through surcharges, respectively. We under-collected fuel costs and deferred for future recovery $42.8 million in 2008 and $17.8 million in 2007. At December 31, 2008, we had deferred fuel under-recovery balances of $39.2 million from our Texas customers and $7.7 million from our New Mexico customers.
Off-system sales. Off-system sales are primarily made in off-peak periods when we have competitive generation capacity available after meeting our regulated service obligations. Typically, we realize a significant portion of our off-system sales margins in the first quarter of each calendar year when our native load is lower than at other times of the year allowing for the sale in the wholesale market of relatively larger amounts of off-system energy generated from lower cost generating resources. Palo Verde’s availability is an important factor in realizing these off-system sales margins. The table below shows MWhs, sales revenue, fuel costs, total margins, and retained margins made on off-system sales for the twelve months ended December 31, 2009, 2008 and 2007 (in thousands except for MWhs).
Off-system sales decreased $116.4 million or 50.1% for the twelve months ended December 31, 2009 when compared to 2008 primarily due to lower market prices for power and a 14.6% decline in MWh sales. Customers receive 25% of off-system sales margins pursuant to the applicable rate agreements. Prior to April 1, 2008, we retained 100% of off-system sales margins allocated to our sales for resale customer. For the twelve months ended December 31, 2009, retained margins decreased $11.3 million when compared to the same period in 2008 due to the lower market power prices.
Off-system sales increased $106.5 million or 84.6% for the twelve months ended December 31, 2008 when compared to 2007 primarily due to increased off-system kWh sales of 59.3% and higher average market prices. Prior to July 1, 2007, we retained 100% of off-system sales margins in New Mexico. For the twelve months ended December 31, 2008, retained margins increased $6.6 million when compared to the same period in 2007 primarily due to the off-system sale to the Imperial Irrigation District (“IID”). In May 2007, we began selling 100 MW of firm energy and 50 MW of contingent energy to IID. The firm portion of this sale is made through a 100 MW purchase of firm energy from Credit Suisse Energy, LLC and the contingent portion is generally from our generating plants.
Comparisons of kWh sales and operating revenues are shown below (in thousands):
(1) Excludes refunds net of fuel surcharges of $0.5 million in 2009 and a $26.0 million surcharge in 2008 related to prior periods Texas deferred fuel revenues.
(2) Represents revenues with no related kWh sales.
(1) Excludes $26.0 million and $22.9 million of deferred fuel revenues recovered through Texas fuel surcharges in 2008 and 2007, respectively.
(2) Represents revenues with no related kWh sales.
Energy expenses
Our sources of energy include electricity generated from our nuclear, natural gas and coal generating plants and purchased power. Palo Verde represents approximately 39% of our available net generating capacity and approximately 61% of our Company generated energy for the twelve months ended December 31, 2009. Large fluctuations in the price of natural gas which also is the primary factor influencing the price of purchased power have had a significant impact on our cost of energy in recent years. Natural gas prices rose significantly in 2007 and the first eight months of 2008. Since August 2008, natural gas prices have declined below 2007 prices.
Energy expenses decreased $205.9 million or 41% for the twelve months ended December 31, 2009 when compared to 2008 primarily due to (i) decreased natural gas costs of $106.4 million due to a 35% decrease in the average price of natural gas and an 11% decrease in MWhs generated with natural gas, and (ii) decreased costs of purchased power of $101.9 million due to a 41% decrease in the average price of power purchased and a 13% decrease in MWhs purchased. Total energy requirements decreased 0.5 million MWhs in 2009 compared to 2008 as a result of decreased off-system sales.
Our energy expenses increased $122.7 million or 33% for the twelve months ended December 31, 2008 when compared to 2007 primarily due to (i) increased costs of purchased power of $83.7 million due to a 44% increase in MWhs purchased and a 15% increase in the market prices for power, and (ii) increased natural gas costs of $32.2 million due to an 18% increase in the average price of natural gas partially offset by a 3% decrease in MWhs generated with natural gas. Total energy requirements increased 1.3 million MWhs in 2008 compared to 2007 almost entirely as a result of increased off-system sales. A significant portion of the increase in off-system sales was related to transactions in which we purchased power to make the sale as reflected in the increase in MWhs purchased in the table below.
The table below details the sources and costs of energy for 2009, 2008 and 2007.
(a) Excludes a reservation charge refund of $2.7 million recorded in 2007.
Other operations expense
Other operations expense increased $15.4 million, or 7.7% in 2009 compared to 2008 primarily due to (i) increased Palo Verde operations expense of $6.3 million, (ii) increased administrative and general expenses of $5.2 million due to increased accruals for employee incentive compensation and increased pension and benefits expenses reflecting a lower discount rate used to determine postretirement benefit costs, and (iii) increased operations expense of $1.9 million at our coal and gas-fired generating plants.
Other operations expense increased $4.5 million, or 2.3% in 2008 compared to 2007 primarily due to (i) increased Palo Verde operations expense of $7.6 million and (ii) increased distribution expense of $2.1 million. These increases were partially offset by decreased administrative and general expenses of $4.7 million primarily due to a decrease in pension and other post-retirement benefit expenses reflecting an increase in the discount rate for the associated liabilities.
Maintenance expense
Maintenance expense decreased $7.5 million, or 11.2% in 2009 compared to 2008 due to (i) decreased maintenance expense at our gas-fired generating plants of $2.7 million as a result of the timing of planned maintenance, (ii) decreased maintenance expense at Palo Verde of $2.7 million, (iii) decreased maintenance at our general and administrative buildings of $1.1 million, and (iv) decreased maintenance of our distribution system of $1.0 million.
Maintenance expense increased $10.1 million, or 17.8% in 2008 compared to 2007 primarily due to (i) increased maintenance expense at our fossil-fueled generating plants of $4.9 million due to major planned maintenance at Newman Unit 3 and Four Corners Unit 5 in 2008 with no comparable activity in 2007 and (ii) increased Palo Verde maintenance expense of $4.6 million due to increased maintenance during refueling outages in 2008 than during refueling outages in 2007.
Depreciation and amortization expense
Depreciation and amortization expense decreased $0.6 million in 2009 compared to 2008 primarily due to completing the amortization of certain fair value adjustments in December 2008 partially offset by increased depreciable plant balances. Depreciation and amortization expense increased $6.2 million, or 8.9% in 2008 compared to 2007 due to increased depreciable plant balances including the replacement of Palo Verde Unit 3 steam generators in January 2008.
Taxes other than income taxes
Taxes other than income taxes increased $0.2 million in 2009 compared to 2008 primarily due to increased property tax accruals for New Mexico and Texas and increased payroll taxes. These increases were partially offset by a decrease in revenue related taxes.
Taxes other than income taxes increased $0.6 million in 2008 compared to 2007 primarily due to increased property taxes in Texas and New Mexico and payroll taxes at Palo Verde.
Other income (deductions)
Other income (deductions) decreased $0.2 million for the twelve months ended December 31, 2009 compared to 2008 primarily due to decreased miscellaneous non-operating income of $1.4 million partially offset by increased allowance for equity funds used during construction (“AEFUDC”) of $1.0 million due to higher balances of construction work in progress in 2009. In 2008, miscellaneous non-operating income included income from an increase in the cash surrender value of key-man life
insurance policies due to a 10-year interest rate adjustment and the settlement of a death benefit with no comparable activity in 2009. During 2009 we incurred impairments and realized losses on equity investments in our decommissioning trusts of $2.2 million compared to $2.9 million in 2008.
Other income (deductions) decreased $1.4 million for the twelve months ended December 31, 2008 compared to the same period last year primarily due to (i) a $4.3 million decrease in income from our decommissioning trust funds when compared to the same period last year and (ii) a decrease in the fair value of our investments in auction rate securities of $1.7 million in 2008 with no comparable activity in 2007. These decreases were partially offset by (i) increased AEFUDC of $2.6 million due to higher balances of construction work in progress in 2008 and (ii) an increase in miscellaneous non-operating income of $1.0 million primarily related to an increase in income from key-man life insurance.
Interest charges (credits)
Interest charges (credits) increased $2.7 million for the twelve months ended December 31, 2009 compared to 2008 primarily due to a $4.8 million increase in interest related to the issuance of $150 million of 7.50% Senior Notes in June 2008 partially offset by a $2.4 million decrease in interest related to our nuclear fuel trust due to lower interest rates.
Interest charges (credits) increased $9.8 million for the twelve months ended December 31, 2008 compared to 2007 primarily due to (i) a $6.5 million increase in interest related to the issuance of $150 million of 7.50% Senior Notes in June 2008, and (ii) a $4.5 million increase in interest related to our auction rate pollution control bonds. Before the pollution control bonds were refinanced in March 2009, the interest rates bid in the weekly auctions increased substantially in 2008 when compared to 2007. These increases were partially offset by a $1.4 million increase in AFUDC and capitalized interest as a result of increased construction work in progress subject to AFUDC and capitalized interest.
Income tax expense
Income tax expense for the twelve months ended December 31, 2009 compared to the same period in 2008, decreased $4.8 million reflecting lower pre-tax income. Income tax expense, increased $3.4 million for the twelve months ended December 31, 2008 compared to the same period in 2007 due to an increase in pretax income and a reduction in permanent tax differences associated with other post-retirement benefits.
New accounting standards
In June 2009, the FASB approved its Accounting Standards Codification (the “Codification 2009”) as the exclusive authoritative reference for U.S. Generally Accepted Accounting Principles (“GAAP”) to be applied by nongovernmental entities. The FASB will not issue new standards in the form of Statements, FASB Staff Positions, or Emerging Issues Task Force Abstracts. Instead, it will issue Accounting Standards Updates (“ASU”). The Codification 2009 is effective for financial statements issued for interim and annual periods ending after September 15, 2009. We adopted the Codification 2009 effective July 1, 2009 without a significant impact on our consolidated financial statements.
Effective January 1, 2009, we adopted FASB guidance which requires a public entity to include share-based compensation awards that qualify as participating securities in both basic and diluted earnings per share. A share-based compensation award is considered a participating security if it receives non-forfeitable dividends or may participate in undistributed earnings with common stock. We award unvested restricted stock which are participating securities and have reflected the effects of this guidance in our basic and diluted earnings per share for all periods presented.
Effective January 1, 2008, we adopted FASB guidance which defines fair value, outlines a framework for measuring fair value, and details the required disclosures about fair value measurements. On April 9, 2009, the FASB issued guidance which required similar disclosure for interim reporting periods ending after June 15, 2009, applied prospectively. This guidance did not have an impact on our consolidated financial statements, but required additional disclosure in our interim reports.
Effective April 1, 2009, we adopted FASB guidance for estimating fair value when the volume and level of activity for the asset or liability has decreased significantly. This guidance requires disclosures about fair value of financial instruments for interim reporting periods of publicly traded companies as well as in annual financial statements. This guidance did not impact amounts reported in our consolidated financial statements, but resulted in additional footnote disclosure.
Effective April 1, 2009, we adopted FASB guidance which amended the other-than-temporary impairment guidance in U.S. GAAP for debt securities to make the guidance more operational and to improve the presentation and disclosure of other-than-temporary impairments on debt and equity securities in the financial statements. This guidance did not have an impact on amounts reported in our consolidated financial statements.
Effective April 1, 2009, we adopted FASB guidance which establishes general standards of accounting and disclosure of events that occur after the balance sheet date, but before financial statements are issued.
In December 2009, we adopted FASB guidance on disclosure of pension and other post-retirement plans that requires additional disclosure of investment policies and strategies, categories of investment and fair value measurements of plan assets, and significant concentrations of risk. This guidance did not impact amounts reported in our consolidated financial statements, but resulted in additional footnote disclosure.
In December 2009, we adopted FASB guidance on the measurement provisions for investments in certain entities that calculate net asset value per share (or its equivalent). These measurement provisions apply to certain investments in funds that do not have readily determinable fair values including private investments, hedge funds, real estate, and other funds. This guidance amends FASB guidance on fair value measurements and allows the use of net asset value per share or its equivalent for the estimation of the fair value for investments in investment companies for which the investment does not have a readily determinable fair value. This guidance did not impact amounts reported in our consolidated financial statements, but did impact our disclosure for pension and other post-retirement plans.
In January 2010, the FASB issued new guidance to improve disclosure requirements related to fair value measurements and disclosures - Overall Subtopic 820-10 of the FASB Accounting Standards Codification. The new requirements include (i) disclosure of significant transfers in and out of Level 1 and Level 2 fair value measurements and the reasons for the transfers; and (ii) disclosure of the reconciliation for Level 3 fair value measurements should include information about purchases, sales, issuances, and settlements on a gross basis. This guidance is effective for interim and annual reporting periods beginning after December 15, 2009, except for the disclosure about purchases, sales, issuances, and settlements in the roll forward of activity in Level 3 fair value measurements. Those disclosures are effective for fiscal years beginning after December 15, 2010, and for interim periods within those fiscal years. This guidance requires additional disclosure on fair value measurements, but does not impact 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
We continue to maintain a strong capital structure which allows us the ability to access financing from the capital markets at a reasonable cost. At December 31, 2009, our capital structure, including common stock, long-term debt, and the current portion of long-term debt and financing obligations, consisted of 46.1% common stock equity and 53.9% debt. Cash from operations was sufficient to fund all of our additions to utility plant and to repurchase common stock in the third and fourth quarters of 2009. At December 31, 2009, our liquidity included $91.8 million in cash and cash equivalents. Substantially all of our cash and cash equivalents are currently held in U.S. treasuries.
Our principal liquidity requirements in the near-term are expected to consist of capital expenditures to expand and support electric service obligations, expenditures for nuclear fuel inventory, interest payments on our indebtedness, and operating expenses including fuel costs, non-fuel operation and maintenance costs and taxes. In addition, we may repurchase common stock in the future.
Capital requirements and resources have been impacted by the timing of the recovery of fuel costs through fuel recovery mechanisms in Texas and New Mexico and our sales for resale customer. We recover actual fuel costs from customers through fuel adjustment mechanisms in Texas, New Mexico, and from our sales for resale customer. We record deferred fuel revenues for the under-recovery or over-recovery of fuel costs until they can be recovered from or refunded to customers. In Texas, fuel costs are recovered through a fixed fuel factor which may be adjusted three times a year.
In the twelve months ended December 31, 2009, we had increased cash from operations due to $64.9 million of fuel over-recoveries compared to the $19.2 million of fuel under-recoveries in 2008. At December 31, 2009, we had a fuel over-recovery balance of $18.0 million, including a $15.7 million over-recovery in Texas, a $2.2 million over-recovery in New Mexico, and a $0.1 million over-recovery from our FERC customer. In January 2010, we received approval in Texas for an interim refund of fuel over-recoveries incurred through November 2009 of $11.8 million with interest to be refunded to customers in February 2010. Fuel over-recovery balances in New Mexico and from our FERC customer will be refunded through fuel adjustment clauses during 2010.
Capital Requirements. During the twelve months ended December 31, 2009, our capital requirements primarily consisted of expenditures for new electric plant and nuclear fuel. Projected utility construction expenditures will consist primarily of expanding and updating our transmission and distribution systems, adding new generation, and making capital improvements and replacements at Palo Verde and other generating facilities. We are constructing Newman Unit 5, a 288 MW gas-fired combined cycle combustion turbine generating unit, which will be completed in two phases at an estimated cost of approximately $230 million, including AFUDC. The first phase of Newman Unit 5 was completed in May 2009 and the second phase is currently expected to be completed before the summer of 2011. As of December 31, 2009, we had expended $158.5 million, including AFUDC, on Newman Unit 5. Estimated construction expenditures for 2010 are approximately $189 million. See Part I, Item 1, “Business - Construction Program”. Capital expenditures were $210.0 million in the twelve months ended December 31, 2009 compared to $198.7 million in the twelve months ended December 31, 2008.
Our capital requirements for nuclear fuel are financed through a trust that borrows under our $200 million credit facility to acquire and process the nuclear fuel. Borrowings under the credit facility for nuclear fuel were $107.0 million as of December 31, 2009 and $93.7 million as of December 31, 2008. Up to $120 million of the credit facility may be used by the trust to finance nuclear fuel. Amounts not drawn for nuclear fuel are available for general corporate purposes including nuclear fuel not financed by the trust. No borrowings were outstanding at December 31, 2009 for general corporate purposes.
The Company does not pay dividends on common stock. Since 1999, we have repurchased approximately 21.1 million shares of common stock at an aggregate cost of $303.4 million, including commissions. During 2009, we repurchased 1,320,384 shares of common stock in the open market at an aggregate cost of $24.1 million. As of December 31, 2009, 200,982 shares remain available for repurchase under the currently authorized program. On February 19, 2010, the Board of Directors authorized an additional repurchase of up to 2 million shares of the Company’s outstanding common stock. We may make purchases of our stock in the future pursuant to our stock repurchase plan at open market prices and may engage in private transactions, where appropriate. The repurchased shares will be available for issuance under employee benefit and stock incentive plans, or may be retired. Our cash requirements for federal and state income taxes vary from year to year based on taxable income, which is influenced by the timing of revenues and expenses recognized for income tax purposes. Due to accelerated tax deductions, tax payments are expected to be minimal in 2010.
We continually evaluate our funding requirements related to our retirement plans, other postretirement benefit plans, and decommissioning trust funds. We contributed $11.8 million and $10.7 million to our retirement plans during the twelve months ended December 31, 2009 and 2008, respectively. We also contributed $3.4 million to our other postretirement benefit plan for both 2009 and 2008, and $7.9 million and $7.2 million to our decommissioning trust funds for 2009 and 2008, respectively. We are in compliance with the funding requirements of the federal government for our benefit plans and decommissioning trust. We will continue to review our funding for these plans in order to meet our future obligations.
Capital Resources. Cash flow from operations was sufficient to fund our capital requirements and repurchases of common stock during the twelve months ended December 31, 2009. Cash generated from operations increased $99.4 million in the twelve months ended December 31, 2009 compared to the same period in 2008 primarily due to the collection of retail fuel revenues in 2009 in excess of fuel expenses. Cash from operations will continue to be a primary source of funds for capital expenditures for electric plant.
We issued $150 million of 7.5% Senior Notes in June 2008. The net proceeds of $148.7 million from the 7.5% Senior Notes were used to repay $44.0 million of working capital borrowings under our credit facility. The remaining proceeds have provided funds for our construction program and other operating requirements. Our Senior Notes are rated “Baa2” by Moody’s and “BBB” by Standard & Poors. We continue to maintain a $200 million credit facility to provide funds for the purchase of nuclear fuel and to provide liquidity to meet our capital requirements before they can be financed with long-term capital sources. At December 31, 2009, we had $93 million of unused credit available on our credit facility. We could seek to obtain additional funds in 2010 to maintain liquidity or meet capital requirements through the issuance of additional long-term debt or an additional credit facility. In September 2009, we received approval from the FERC to enter into an additional $100 million credit facility by August 2011 to supply additional liquidity. We believe that we will have adequate liquidity through our current cash balances, cash from operations, and our credit facility to meet all of our anticipated cash requirements through 2010 based on current projections. We could also seek to issue additional long-term debt or obtain funds through the additional credit facility to finance capital requirements in 2010 and 2011 in addition to funds from operations and our existing or expanded credit facility.
Contractual Obligations. Our contractual obligations as of December 31, 2009 are as follows (in thousands):
(1) We have two issuances of Senior Notes. In May 2005, we issued $400.0 million aggregate principal amount of 6% Senior Notes due May 15, 2035. In June 2008, we issued $150.0 million aggregate principal amount of 7.5% Senior Notes due March 15, 2038.
(2) We have four series of pollution control bonds which are scheduled for remarketing and/or mandatory tender, one in 2012 and the other three in 2040.
(3) This reflects obligations outstanding under the $200 million credit facility used to finance nuclear fuel including interest based on actual interest rates at the end of 2009.
(4) Amount is based on the minimum volumes per the contract and market and/or contract price at the end of 2009. Gas obligation includes a gas storage contract and a gas transportation contract.
(5) Some of the nuclear fuel contracts are based on a fixed price adjusted for an index. The index used is the index at the end of 2009.
(6) These obligations include our minimum contractual funding requirements for the non-qualified retirement income plan and the other postretirement benefits for 2010. We have no minimum contractual funding requirement related to our retirement income plan for 2010. However, we may decide to fund at higher levels and expect to contribute $10.2 million and $3.4 million to our retirement plans and postretirement benefit plan in 2010, as disclosed in Part II, Item 8, Notes to Consolidated Financial Statements, Note L, Employee Benefits. Minimum contractual funding requirements for 2011 and beyond are not included due to the uncertainty of interest rates and the related return on assets.
(7) These obligations represent funding requirements under the ANPP Participation Agreement based on the current rate of return on investments.
(8) In June 2008, we entered into an agreement to lease land in El Paso adjacent to the Newman Power Station under a lease which expires in June 2033 with a renewal option of 25 years. In addition, we lease certain warehouse facilities in El Paso under a lease which expires in December 2014. We also have several other leases for office and parking facilities which expire within the next five years.
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.
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, except for our revolving credit facility which is based on floating rates.
To the extent the revolving credit facility is solely utilized for nuclear fuel purchases, interest rate risk, if any, related to the revolving credit facility is substantially mitigated through the operation of the PUCT and NMPRC rules which establish energy cost recovery clauses (“fuel clauses”). Under these rules and fuel clauses, actual energy costs, including interest expense on nuclear fuel financing, are recovered from our customers.
Our decommissioning trust funds consist of equity securities and fixed income instruments and are carried at fair 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 $74.6 million and $57.2 million as of December 31, 2009 and 2008, respectively. A hypothetical 10% increase in interest rates would reduce the fair values of these funds by $1.1 million and $0.6 million based on their fair values at December 31, 2009 and 2008, respectively.
Equity Price Risk
Our decommissioning trust funds include marketable equity securities of approximately $60.8 million and $54.1 million at December 31, 2009 and 2008, respectively. A hypothetical 20% decrease in equity prices would reduce the fair values of these funds by $12.2 million and $10.8 million based on their fair values at December 31, 2009 and 2008, respectively. Declines in market prices could require that additional amounts be contributed to our decommissioning trusts to maintain minimum funding requirements.
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 PUCT 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, 2010, 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 FASB guidance for accounting for derivative instruments and hedging activities and are not recorded at their fair value in our financial statements. Because of the operation of the PUCT and NMPRC rules and our fuel clauses, these contracts do not expose us to significant commodity price risk.
Management Report on Internal Control Over Financial Reporting
The 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, 2009. In making this assessment, the Company’s management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control-Integrated Framework.
Based on its assessment, management believes that, as of December 31, 2009, 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 the Company’s internal control over financial reporting. This report appears on page 59 of this report.
Item 8.
Item 8. Financial Statements and Supplementary Data
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, 2009 and 2008, 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, 2009. We also have audited El Paso Electric Company’s internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. El Paso Electric Company’s management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on these consolidated financial statements and an opinion on the Company’s internal control over financial reporting based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the consolidated financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
A 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, 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, 2009 and 2008, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2009, in conformity with U.S. generally accepted accounting principles. Also in our opinion, El Paso Electric Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
/s/ KPMG LLP
Houston, Texas
February 25, 2010
EL PASO ELECTRIC COMPANY AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
See accompanying notes to consolidated financial statements.
EL PASO ELECTRIC COMPANY AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS (Continued)
See accompanying notes to consolidated financial statements.
EL PASO ELECTRIC COMPANY AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands except for share data)
See accompanying notes to consolidated financial statements.
EL PASO ELECTRIC COMPANY AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF COMPREHENSIVE OPERATIONS
(In thousands)
See accompanying notes to consolidated financial statements.
EL PASO ELECTRIC COMPANY AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCK EQUITY
(In thousands except for share data)
See accompanying notes to consolidated financial statements.
EL PASO ELECTRIC COMPANY AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
See accompanying notes to consolidated financial statements.
INDEX TO NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
A. Summary of Significant Accounting Policies
General. El Paso Electric Company is a public utility engaged in the generation, transmission and distribution of electricity in an area of approximately 10,000 square miles in west Texas and southern New Mexico. El Paso Electric Company also serves a full requirements wholesale customer in Texas.
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 J. 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 FASB Guidance for Regulated Operations. Regulated electric utilities typically prepare their financial statements in accordance with the Financial Accounting Standards Board (“FASB”) guidance for regulated operations. FASB guidance for regulated operations requires the Company to include an allowance for equity and borrowed funds used during construction (“AEFUDC” and “ABFUDC”) as a cost of construction of electric plant in service. AEFUDC is recognized as income and ABFUDC is shown as capitalized interest charges in the Company’s statement of operations. FASB guidance for regulated operations also requires the Company to show certain recoverable costs as either assets or liabilities on a utility’s balance sheet if the regulator provides assurance that these costs will be charged to and collected from the utility’s customers (or has already permitted such cost recovery) or will be credited or refunded to the utility’s customers. The resulting regulatory assets or liabilities are amortized in subsequent periods based upon the respective amortization periods reflected in a utility’s regulated rates. See Note C.
The Company applies FASB guidance for regulated operations for all three of the jurisdictions it operates in. However, prior to April 1, 2008, the Company did not apply FASB guidance for regulated operations to the Company’s FERC jurisdictional operations. The Company’s FERC jurisdictional
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
customer, Rio Grande Electric Cooperative (“RGEC”), had been operating under an agreement which terminated March 31, 2008. The FERC approved a new agreement with RGEC effective April 1, 2008. The rates charged RGEC are based upon the Company’s actual cost of service and are updated annually. The Company determined that the new agreement re-established regulated cost-based rates for RGEC and met the criteria for the re-application of FASB guidance for regulated operations as of April 1, 2008. The re-application of FASB guidance for regulated operations to the Company’s FERC jurisdictional customer resulted in a $0.2 million increase in regulatory assets and a $0.2 million pre-tax gain which was recorded as miscellaneous non-operating income in the second quarter of 2008.
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 FASB guidance for reporting comprehensive income.
Utility Plant. Depreciation is provided on a straight-line basis over the estimated remaining lives of the assets (ranging from 3 to 51 years). The cost of repairs and minor replacements are charged to the appropriate operating expense accounts and the cost of renewals and betterments are capitalized. 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 the funding 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 D.
Impairment of Long-Lived Assets. Pursuant to FASB guidance for impairment or disposal of long-lived assets, such as property, plant, and equipment and purchased intangibles subject to amortization; long-lived assets 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.
AFUDC and Capitalized Interest. The Company capitalizes interest (ABFUDC) and common equity (AEFUDC) costs to construction work in progress and capitalizes interest to nuclear fuel in process in accordance with the FERC Uniform System of Accounts as provided for in FASB guidance. AFUDC is a non-cash component of income and is calculated monthly and charged to all new eligible construction and capital improvement projects. The AFUDC rates utilized in 2009, 2008 and 2007 were 8.94%, 8.57% and 8.43%, respectively.
EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Asset Retirement Obligation. The Company complies with FASB guidance for asset retirement obligations. FASB guidance 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 FASB guidance 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 and legal obligations 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 E. Under FASB guidance, 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).
Cash and Cash Equivalents. All temporary cash investments with an original maturity of three months or less are considered cash equivalents.
Investments in Debt Securities. In 2007, the Company invested excess cash in auction rate securities with contract maturity dates that extended beyond three months. These securities have interest rates that reset frequently, and historically had provided a liquid market to sell the securities to meet cash requirements. These securities were and still are classified as trading securities by the Company. The auction rate securities had successful auctions through January 2008. However, since February 13, 2008, auctions for $4.0 million of these investments have not been successful, resulting in the inability to liquidate these investments. These investments continue to pay interest. The Company reclassified them to deferred charges and other assets as of March 31, 2008 and has adjusted the carrying amount to fair value. See Note N.
Investments. The Company’s marketable securities, included in decommissioning trust funds in the balance sheets, are reported at fair value and consist of cash, 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 N.
Derivative Accounting. The Company complies with FASB guidance for accounting for derivative instruments and hedging activities which requires the recognition of derivatives as either assets or liabilities in the balance sheet with measurement of those instruments at fair value. Any changes in the fair value of these instruments are recorded in earnings or other comprehensive income. See Note N.
EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 billed under base rates and a fixed fuel factor approved by the Public Utility Commission of Texas (the “PUCT”). The Company’s New Mexico retail customers and its sales for resale customer are billed under base rates and a fuel adjustment clause which is adjusted monthly, as approved by the New Mexico Public Regulation Commission (“NMPRC”) and the FERC. The Company’s recovery of energy expenses 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 customers is reflected as over/undercollection of fuel revenues in the consolidated balance sheets. See Note B.
Revenues. Accounts receivable include accrued unbilled revenues of $18.2 million and $18.6 million at December 31, 2009 and 2008, respectively. The Company presents sales net of sales taxes in its consolidated statements of operations.
Allowance for Doubtful Accounts. Additions, deductions and balances for allowance for doubtful accounts for 2009, 2008 and 2007 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 in accordance with FASB guidance for income taxes. 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 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. The Company recognizes tax assets and liabilities for uncertain tax positions in accordance with the recognition and measurement criteria of FASB guidance for uncertainty in income taxes. See Note I.
Earnings per Share. In accordance with FASB guidance, the Company’s restricted stock awards are participating securities and earnings per share must be calculated using the two-class method in both the basic and diluted earnings per share calculations. For the basic earnings per share calculation, net
EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
income is allocated to restricted stock awards and to the weighted average number of shares outstanding. The net income allocated to the weighted average number of shares outstanding is then divided by the weighted average number of shares outstanding to derive the basic earnings per share. For the diluted earnings per share, net income is allocated to restricted stock awards and to the weighted average number of shares and dilutive potential shares outstanding. The Company’s dilutive potential shares outstanding amount is calculated using the treasury stock method for the unvested performance shares and outstanding stock options. Net income allocated to the weighted average number of shares and dilutive potential shares is then divided by the weighted average number of shares and dilutive potential shares outstanding to derive the diluted earnings per share. See Note F.
Stock-Based Compensation. The Company has a stock-based long-term incentive plan. The Company is required under FASB guidance 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. Such costs are recognized over the period during which an employee is required to provide service in exchange for the award (the “requisite service period”) which typically is the vesting period. Compensation cost is not recognized for anticipated forfeitures prior to vesting of equity instruments. See Note F.
Pension and Postretirement Benefit Accounting. For a full discussion of the Company’s accounting policies for its employee benefits. See Note L.
Other New Accounting Standards. In June 2009, the FASB approved its Accounting Standards Codification (the “Codification 2009”) as the exclusive authoritative reference for U.S. Generally Accepted Accounting Principles (“GAAP”) to be applied by nongovernmental entities. The FASB will not issue new standards in the form of Statements, FASB Staff Positions, or Emerging Issues Task Force Abstracts. Instead, it will issue Accounting Standards Updates (“ASU”). The Codification 2009 is effective for financial statements issued for interim and annual periods ending after September 15, 2009. The Company adopted the Codification 2009 effective July 1, 2009 without a significant impact on the Company’s consolidated financial statements.
Effective January 1, 2009, the Company adopted FASB guidance which requires a public entity to include share-based compensation awards that qualify as participating securities in both basic and diluted earnings per share. A share-based compensation award is considered a participating security if it receives non-forfeitable dividends or may participate in undistributed earnings with common stock. The Company awards unvested restricted stock which are participating securities and has reflected the effects of this guidance in the Company’s basic and diluted earnings per share for all periods presented.
Effective January 1, 2008, the Company adopted FASB guidance which defines fair value, outlines a framework for measuring fair value, and details the required disclosures about fair value measurements. On April 9, 2009, the FASB issued guidance which required similar disclosure for interim reporting periods ending after June 15, 2009, applied prospectively. This guidance did not have an impact on the Company’s consolidated financial statements, but required additional disclosure in the Company’s interim reports.
EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Effective April 1, 2009, the Company adopted FASB guidance for estimating fair value when the volume and level of activity for the asset or liability has decreased significantly. This guidance requires disclosures about fair value of financial instruments for interim reporting periods of publicly traded companies as well as in annual financial statements. This guidance did not impact amounts reported in the Company’s consolidated financial statements, but resulted in additional footnote disclosure.
Effective April 1, 2009, the Company adopted FASB guidance which amended the other-than-temporary impairment guidance in U.S. GAAP for debt securities to make the guidance more operational and to improve the presentation and disclosure of other-than-temporary impairments on debt and equity securities in the financial statements. This guidance did not have an impact on amounts reported in the Company’s consolidated financial statements.
Effective April 1, 2009, the Company adopted FASB guidance which establishes general standards of accounting and disclosure of events that occur after the balance sheet date, but before financial statements are issued.
In December 2009, the Company adopted FASB guidance on disclosure of pension and other post-retirement plans that requires additional disclosure of investment policies and strategies, categories of investment and fair value measurements of plan assets, and significant concentrations of risk. This guidance did not impact amounts reported in the Company’s consolidated financial statements, but resulted in additional footnote disclosure.
In December 2009, the Company adopted FASB guidance on the measurement provisions for investments in certain entities that calculate net asset value per share (or its equivalent). These measurement provisions apply to certain investments in funds that do not have readily determinable fair values including private investments, hedge funds, real estate, and other funds. This guidance amends FASB guidance on fair value measurements and allows the use of net asset value per share or its equivalent for the estimation of the fair value for investments in investment companies for which the investment does not have a readily determinable fair value. This guidance did not impact amounts reported in the Company’s consolidated financial statements, but did impact the Company’s disclosure for pension and other post-retirement plans.
In January 2010, the FASB issued new guidance to improve disclosure requirements related to fair value measurements and disclosures - Overall Subtopic 820-10 of the FASB Accounting Standards Codification. The new requirements include (i) disclosure of significant transfers in and out of Level 1 and Level 2 fair value measurements and the reasons for the transfers; and (ii) disclosure of the reconciliation for Level 3 fair value measurements should include information about purchases, sales, issuances, and settlements on a gross basis. This guidance is effective for interim and annual reporting periods beginning after December 15, 2009, except for the disclosure about purchases, sales, issuances, and settlements in the roll forward of activity in Level 3 fair value measurements. Those disclosures are effective for fiscal years beginning after December 15, 2010, and for interim periods within those fiscal
EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
years. This guidance requires additional disclosure on fair value measurements, but does not impact the Company’s consolidated financial statements.
B. Regulation
General
The rates and services of the Company are regulated by incorporated municipalities in Texas, the PUCT, the NMPRC, and the FERC. The PUCT 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 and compliance with federally-mandated reliability standards. The decisions of the PUCT, NMPRC and the FERC are subject to judicial review.
Texas Regulatory Matters
Texas Freeze Period. The Company has entered into agreements (“Texas Rate Agreements”) with El Paso, PUCT staff and other parties in Texas that provide for most retail base rates to remain at their current level through June 30, 2010. During the rate freeze period, if the 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 an amount equal to 50% of the Texas jurisdictional pretax return in excess of the ceiling. The range is based upon a risk premium analysis used in rate proceedings to establish a utility’s return on equity, and as of December 31, 2009, the range would be approximately 9.06% to 13.06%. The Company’s return on equity fell within this range during 2009. Also pursuant to the Texas Rate Agreements, the Company agreed to share with its Texas customers 25% of off-system sales margins increasing to 90% after June 30, 2010 through June 30, 2015.
Fuel and Purchased Power Costs. Although the Company’s base rates are frozen pursuant to the Texas Rate Agreements, the Company’s actual fuel costs, including purchased power energy costs, are recoverable from its customers. The PUCT has adopted a rule establishing the recovery of fuel costs (“Texas Fuel Rule”) that allows the Company to seek adjustments to its fixed fuel factor three times per year in February, June and October. The Texas Fuel Rule provides for the fixed fuel factor to be based upon projected fuel and purchased power costs and projected kilowatt-hour sales for a twelve-month period. The Texas Fuel Rule also allows for the Company to request a formula to determine its fuel factor. Once a formula is approved, the Company could seek to revise its fixed fuel factor based upon the approved formula at least four months after its last revision except in the month of December. The Texas Fuel Rule requires the Company to request to refund fuel costs in any month when the over-recovery balance exceeds a threshold material amount and it expects to continue to be materially over-recovered. The Texas Fuel Rule also permits the Company to seek to surcharge fuel under-recoveries in any month the balance exceeds a threshold material amount and it expects to continue to be materially under-recovered. Fuel over and under recoveries are considered material when
EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
they exceed 4% of the previous twelve months fuel costs. All such fuel revenue and expense activities are subject to periodic final review by the PUCT in fuel reconciliation proceedings.
On January 8, 2008, the Company filed a request with the PUCT in Docket No. 35204 to surcharge approximately $30.1 million, including interest, of under-recovered fuel and purchased power costs to be collected over a twelve-month period. The fuel under-recoveries were incurred during the period December 2005 through November 2007. On April 11, 2008, the PUCT issued a final order approving the fuel surcharge to be collected over a twelve-month period beginning in May 2008.
On July 8, 2008, the Company filed a petition in Docket No. 35856 with the PUCT to increase its fixed fuel factors and to surcharge $39.5 million of under-recovered fuel and purchased power costs including interest. The surcharge was based upon actual under-recoveries for the period December 2007 through May 2008 and expected under-recoveries for June and July 2008. On September 25, 2008, the PUCT issued a final order approving an increase in the Company’s Texas jurisdictional fixed fuel factors of $38.8 million or 21.5% annually beginning with customer bills rendered in October 2008. In addition, the PUCT approved the recovery of $39.5 million in fuel under-recoveries over an 18-month period beginning in October 2008.
On April 1, 2009, the Company filed a petition with the PUCT in Docket No. 36864 to terminate the interim fuel surcharge which had been authorized in Docket No. 35856. The Company’s request was a result of the over-recovery of fuel costs under the Company’s fixed fuel factor effective in October 2008 which largely offset the remaining balance of the fuel surcharge. The fuel over-recoveries were the result of the significant drop in natural gas prices since the fixed fuel factor went into effect in October 2008. On April 23, 2009, the Company received approval from the PUCT to terminate the fuel surcharge effective for customer bills rendered in May 2009 and thereafter.
On June 5, 2009, the Company filed a petition with the PUCT in Docket No. 37086 to decrease its fixed fuel factors by 13.1%, or $27.9 million. On July 30, 2009, the PUCT approved the new factors effective for customer bills rendered beginning in August 2009.
On September 1, 2009, the Company filed a petition in Docket No. 37433 to refund $12.0 million in fuel cost over-recoveries, including interest, for the period of July 2008 through July 2009. The Company entered into a stipulation in October 2009 that included the August 2009 over-recovery in the refund for a total of $16.8 million, including interest, and provided for the refund to be paid in November and December, 2009. On October 23, 2009, the PUCT issued an order approving the stipulation.
On December 17, 2009, the Company filed a petition with the PUCT Docket No. 37788 requesting authority to implement a one-month, interim fuel refund of $11.8 million in fuel cost over-recoveries, including interest, for the period September through November 2009. On January 20, 2010, a stipulation was filed that resolves all of the issues in this proceeding. The stipulation provides for the Company to implement a fuel refund for the net over-recovery of $11.8 million, including interest, in the
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month of February, 2010. On January 21, 2010, the administrative law judge assigned to the docket issued an order approving the implementation of interim rates to allow the requested refund to be made. The PUCT approved the stipulation at its open meeting on February 11, 2010.
Palo Verde Performance Standards. The PUCT established performance standards for the operation of Palo Verde pursuant to which each Palo Verde unit is evaluated annually to determine whether its three-year rolling average capacity factor entitles the Company to a reward or subjects it to a penalty. The capacity factor is calculated as the ratio of actual generation to maximum possible generation. If the capacity factor, as measured on a station-wide basis for any consecutive 36-month period, should fall below 35%, the parties to the Texas Rate Agreements can seek to remove Palo Verde from base rates and 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 2009, 2008 and 2007 to be approximately $0.7 million, $0.1 million, and $0.6 million, respectively. Performance rewards are not recorded on the Company’s books until the PUCT has made 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.
The Company agreed to contribute Palo Verde rewards approved in its fuel reconciliation proceeding in PUC Docket No. 23530 to assist low-income customers in paying their utility bills. In compliance with the PUCT order, the Company sought and received approval by the El Paso City Council in January 2006 to remit to El Paso approximately $5.8 million in Palo Verde performance reward funds to fund demand side management programs such as weatherization with a focus on programs to assist small business and commercial customers. As of December 31, 2009, $2.5 million, including accrued interest, remains to be paid under these agreements and is recorded as a liability on the Company’s balance sheet.
Renewable Energy Requirements. Notwithstanding the PUCT’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 is required to annually obtain its pro rata share of renewable energy credits as determined by the Electric Reliability Council of Texas (the “Program Administrator”). 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 expects to meet its obligations for renewable energy credits for 2009.
2007 Energy Efficiency Legislation. The Texas legislature has established energy efficiency goals for cost-effective energy efficiency for residential and commercial customers equivalent to at least 15% of the annual growth in demand by December 31, 2008 and 20% of the annual growth in demand by December 31, 2009. Among other things, the legislation requires the PUCT to establish an energy efficiency cost recovery factor for ensuring cost recovery for utility expenditures made to satisfy the
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energy efficiency goal. The legislation provides that utilities that are unable to establish an energy efficiency cost recovery factor in a timely manner due to a rate freeze will be allowed to defer the costs of complying with the energy efficiency goal and recover such deferred costs at the end of the rate freeze period. On September 8, 2008 in Docket No. 35612, the PUCT approved the Company’s request to defer these costs and recover them through a cost recovery factor upon expiration of its rate freeze period. As of December 31, 2009, the Company had deferred as a regulatory asset, $4.0 million of energy efficiency costs.
2009 Texas Retail Rate Case. On December 9, 2009, the Company filed an application with the PUCT for authority to change rates, to reconcile fuel costs, to establish formula-based fuel factors, and to establish an energy efficiency cost-recovery factor. This case was assigned PUCT Docket No. 37690. The test year for the base-rate case is July 2008 through June 2009. The Company seeks to increase its base-rate revenue requirement by $51.6 million over current base rates, or a 12.89% annual increase, based on a total non-fuel base revenue requirement of $451.7 million for the Company’s retail jurisdiction. The Company’s fuel-reconciliation request addresses fuel and purchased power costs and fuel-factor revenues for the period March 1, 2007 through June 30, 2009. The Company’s request to implement a fuel-factor formula would change its historically-used method of establishing fuel and purchased power costs based upon a projected test year period to a PUCT-approved, utility-specific formula pursuant to PUCT Rules. Finally, the Company’s request to implement an energy-efficiency cost-recovery factor would recover its ongoing reasonable energy-efficiency costs in addition to the previous costs that were deferred for future recovery due to the Company’s rate freeze.
On January 20, 2010, the administrative law judge issued an order approving an agreed procedural schedule that provides for intervenor and staff testimony with their recommended rate changes to be filed in April and hearings to begin on May 10, 2010. The agreed procedural schedule provides that, if the PUCT has not approved final rates by August 20, 2010, current rates will be in effect on a temporary basis from such date, subject to true-up to the final approved base rates.
Electric Restructuring. The Texas Restructuring Law required certain investor-owned electric utilities to separate power generation activities and retail service activities from transmission and distribution activities by January 1, 2002, and on that date, retail competition for generation services was instituted in some parts of Texas. However, the PUCT has delayed retail competition in the Company’s Texas service territory by approving a rule which identifies various milestones for the Company to reach before competition can begin. The first milestone calls for the development, approval by the FERC, and commencement of independent operation of a regional transmission organization (“RTO”) in the area that includes the Company’s service territory, including the development of retail market protocols to facilitate retail competition (see “FERC Regulatory Matters - RTOs” below). The complete transition to retail competition would occur upon the completion of the last milestone, which would be the PUCT’s final evaluation of the market’s readiness to offer fair competition and reliable service to all retail customers. The Company believes this rule delays retail competition in its Texas service territory indefinitely. There is substantial uncertainty about both the regulatory framework and market conditions that will exist if and when retail competition is implemented in the Company’s service territory, and the
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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, if it were to be implemented.
New Mexico Regulatory Matters
2007 New Mexico Stipulation. In July 2007, the NMPRC issued a final order approving a stipulation (“2007 New Mexico Stipulation”) addressing all issues in the 2006 rate filing in Case No. 06-00258-UT. The 2007 New Mexico Stipulation provided for a $5.8 million non-fuel base rate increase, established the amount of fuel included in base rates at $0.04288 per kWh, and modified the Company’s Fuel and Purchased Power Cost Adjustment Clause (the “FPPCAC”). Any difference between actual fuel and purchased power costs and the amount included in base rates was recovered or refunded through the FPPCAC. Rates continued in effect until changed by the NMPRC following the Company’s next rate case. The 2007 New Mexico Stipulation required the Company to file its next general rate case no later than May 29, 2009 using as a base period the twelve months ending December 31, 2008. Under NMPRC statutes, new rates would become effective no later than July 2010 unless otherwise extended. The Company complied with the 2007 New Mexico Stipulation and filed its required rate case on May 29, 2009.
The 2007 New Mexico Stipulation provided for recovery through the FPPCAC of the cost of capacity and energy provided to New Mexico retail customers from the deregulated Palo Verde Unit 3. The amount to be recovered was based upon the monthly contract cost of capacity and energy for power purchased under the Southwestern Public Service Company (“SPS”) purchased power contract. In February and March 2009, the volumes delivered to the Company over the transmission tie used to import SPS power were materially lower than normal due to operational constraints. This reduction in volume resulted in contract formula prices for Palo Verde Unit 3 power that were significantly higher than what were foreseen by the 2007 New Mexico Stipulation. The Company addressed this price spike due to operational constraints by proposing to adjust the proxy price in February 2009 to $54.27 per MWh (January 2009 monthly calculated price) and in March 2009 to $64.38 per MWh (12 months ending January 2009 average price) which is approximately 28% and 55% of the price calculated utilizing the formula from the 2007 New Mexico Stipulation. Because the operational constraints limiting the SPS purchases were expected to continue during 2009, the Company on April 24, 2009 requested approval of an unopposed variance to the calculation of the Palo Verde Unit 3 proxy price to be the lower of the monthly cost of capacity and energy under the SPS purchased power contract or the average cost of capacity and energy under the SPS purchased power contract for the twelve months ended January 2009 of $64.38 per MWh.
The SPS purchased power contract was terminated September 30, 2009, see Note J. The 2007 New Mexico Stipulation provided that upon termination of the SPS contract, the proxy price would be the average cost of SPS capacity and energy during the twelve months prior to contract termination. As a result, the price of deregulated Palo Verde Unit 3 power was set at $47.77 during the months of October 2009 through December 2009.
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The 2007 New Mexico Stipulation also required 25% of jurisdictional off-system sales margins to be credited to customers through the FPPCAC until July 2010 when 90% of jurisdictional off-system sales margins will be credited to customers.
2009 New Mexico Stipulation. On May 29, 2009, the Company filed with the NMPRC a petition to increase non-fuel and purchased power base rates by $12.7 million annually. The filing reflected a projected reduction of $21.3 million in fuel related revenues based upon the difference in revenues for the test year ended December 31, 2008 and the forecast period revenues (forecasted fuel and purchased power costs for the twelve month period beginning July 1, 2010) for a projected net decrease in New Mexico jurisdictional fuel and purchased power revenues of $8.6 million. The filing complied with the 2007 New Mexico Stipulation requirement in the NMPRC’s Final Order in Case No. 06-00258-UT to file a general rate case by May 30, 2009 using a test year ended December 31, 2008. The 2009 rate case was docketed as NMPRC Case No. 09-00171-UT.
A unanimous settlement of all issues in the case and an unopposed, comprehensive stipulation (the “2009 New Mexico Stipulation”) was filed on October 8, 2009. The 2009 New Mexico Stipulation resolved all issues and provided for an increase in New Mexico jurisdictional non-fuel and purchased power base rate revenues of $5.5 million. The 2009 New Mexico Stipulation provided for the revision of depreciation rates for the Palo Verde nuclear generating plant to reflect a 20-year life extension and depreciation rates for other plant in service. The 2009 New Mexico Stipulation also provided for the continuation of the Company’s FPPCAC without conditions or variance and established the base fuel factor at $0.04362 per kWh. In addition, the 2009 New Mexico Stipulation modified the market pricing of capacity and energy provided by Palo Verde Unit 3 due to the termination of the SPS contract in September 2009. Pursuant to the 2009 New Mexico Stipulation, Palo Verde Unit 3 capacity and energy will be included in the FPPCAC based upon an existing purchased power contract with Credit Suisse Energy, LLC.
The Company and Staff filed testimony in support of the 2009 New Mexico Stipulation on October 22, 2009. A public evidentiary hearing on the merits of the 2009 New Mexico Stipulation was held before the Commission on November 4, 2009. On December 10, 2009, the NMPRC issued a final order conditionally approving and clarifying the unopposed stipulation. The stipulated rates approved in the final order went into effect with January 2010 bills.
Investigation into Recovering County Franchise Fees. On December 10, 2009, the NMPRC issued an order in NMPRC Case No. 09-00421-UT, requiring the Company to show cause why it should collect franchise fees from its customers on behalf of Doña Ana and Otero Counties (the “Counties”). The Company responded to the order on January 5, 2010. On January 26, 2010, the NMPRC issued its decision concluding that the imposition of franchise fees by New Mexico counties is not authorized under New Mexico law and, therefore, the Company may not pass through to its customers some past and all ongoing franchise fees imposed by the Counties. The order concluded that only “home rule” municipalities, who had adopted a charter under the state constitution, could impose franchise fees or taxes, provided the residents so voted.
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As a result of its findings, the NMPRC directed the Company to immediately cease passing through to its customers any franchise fees paid by the Company to the Counties. The NMPRC also directed the Company to refund to its customers in the Counties the amount of franchise fees charged to those customers since June 1, 2004, plus interest. The Company estimates that its refund obligation under the order would be approximately $5.7 million, plus accrued interest of approximately $1.0 million through December 31, 2009. The order stated that the Company was required to refund these franchise fees to customers over a three-year period through a credit on customer bills and file tariffs for refunding within three days. On January 29, 2010, the NMPRC granted the Company’s request to extend its deadline for compliance with the order until February 12, 2010. Interest will continue to accrue on the unamortized balance until fully refunded. The order does not relieve the Company of its obligation to pay franchise fees to the Counties but states that this issue must be addressed by the New Mexico courts.
The Company immediately filed a Notice of Appeal with the New Mexico Supreme Court on January 27, 2010 (the “Appeal”), seeking to set aside the order on legal and jurisdictional grounds. The Company followed with a motion for Emergency Stay on January 29, 2010, asking the New Mexico Supreme Court to stay the order pending the Appeal. The Company also asked the NMPRC, on February 12, 2010, to delay implementation of its order pending the Appeal. The Counties moved to intervene in the Appeal on February 10, 2010, and have also informed the Company they intend to pursue their own legal actions opposing the order. The Company has placed any pending franchise payments to the Counties in escrow accounts pending resolution of the proceedings. On February 22, 2010, the New Mexico Supreme Court granted the Company’s motion for Emergency Stay pending the outcome of the Appeal and granted the Counties’ motion to intervene in the Appeal. The New Mexico legislature recently passed legislation that if signed by the governor, could clarify the legality of the Company’s existing franchise agreements with the Counties. The Company cannot predict the outcome of the proceedings.
The Company will also review its legal options to terminate any future obligation to pay franchise fees to the Counties and to seek reimbursement from the Counties if refunds are ultimately required. The Company cannot predict the outcome of these legal reviews or any legal proceedings that may follow.
FPPCAC Rulemaking and Workshops. The NMPRC has docketed workshops (Case No. 07-00389-UT) to review consistency and potential changes to the FPPCAC rule in New Mexico. Comments have been filed by parties and workshops have been held for discussion and consideration of any changes to the existing FPPCAC rule that could be included in a new rulemaking proceeding. The NMPRC has no proposed rule revisions to date.
Pollution Control Bond Refunding. On March 20, 2008, the Company filed an application with the NMPRC requesting authority for long-term securities transactions necessary to refund and reissue certain Pollution Control Refunding Revenue Bonds (the “PCBs”). On April 22, 2008, the NMPRC issued a final order granting the Company the authority to enter into the securities transactions necessary to refund and reissue the Company’s Series B and Series C PCBs. On March 26, 2009, the Company completed a refunding transaction related to an aggregate principal amount of $100.6 million in pollution control indebtedness.
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Notice of Investigation of Rates. On August 3, 2007, the Company received a “Notice of Investigation of Rates of El Paso Electric Company” from the NMPRC in Case No. 07-00317-UT. On August 21, 2007, the NMPRC requested that the Company file a response to the issues, including the reasonableness of fuel and purchased power costs. On September 7, 2007, the Company filed its response and requested that the NMPRC suspend its investigation and close the docket. No further action has been taken by the NMPRC and the docket is moot since the rates established in Case No. 07-00317-UT are no longer in effect.
New Mexico Investigation into Executive Compensation. In December 2007, the NMPRC initiated an investigation into executive compensation of investor-owned gas and electric public utilities. In its order initiating the investigation, the NMPRC required each utility to provide information on compensation of executive officers and directors for the period 1977-2006. The Company provided the requested information. No further action has been taken by the NMPRC.
2009 New Mexico Integrated Resource Plan Filing. On July 16, 2009, the Company submitted its initial Integrated Resource Plan (“IRP”) pursuant to the requirements of NMPRC Rule 17.7.3. The filing identifies the Company’s four-year action plan to meet resource needs based upon a twenty-year resource plan. The four-year action plan includes the addition of a natural gas-fired combustion turbine in 2012; a competitive-bid request for proposals to add a combined cycle plant in three phases in 2013, 2014, and 2016; evaluation of a direct load control project for possible integration in the resource plan; and a competitive-bid request for proposals to acquire additional wind and biomass renewable resources in 2013 and 2015 to comply with the New Mexico Renewable Portfolio Standard Requirements. The NMPRC accepted the proposed IRP as compliant with its rules without a hearing in August 2009.
2009 New Mexico Annual Renewable Procurement Plan Filing. On July 1, 2009, the Company filed its 2009 Annual Renewable Procurement Plan in compliance with the New Mexico Renewable Energy Act. The Company’s 2009 plan was designed to meet the full renewable portfolio standard (“RPS”) of 6 percent of New Mexico jurisdictional retail energy sales for 2010 and 10 percent beginning in 2011. The Company requested approval by the NMPRC of the following proposals: 1) to increase the solar resources used for RPS compliance pursuant to the long-term contract with New Mexico SunTower, LLC; 2) to pay an additional $0.015 per kWh for renewable energy credits (“RECs”) obtained from a biomass energy facility; and 3) to modify and expand the Company’s existing REC purchase program for customer-installed qualifying facilities up to 10 kW and to add a program for customer-installed qualifying facilities of 10 kW to 100 kW. Hearings were held on October 1, 2009. On December 22, 2009, the NMPRC issued its final order substantially approving the Company’s proposed procurement plan modified to increase the price paid for small, customer-owned solar generated energy from the proposed price of $0.10 per kWh to $0.12 per kWh.
Investigation into the Service Quality of El Paso Electric Company. On October 22, 2009, NMPRC Staff filed a petition requesting an investigation into the quality of service of the Company’s power distribution system in the Santa Teresa Industrial Park, based upon a report prepared for customers
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in that area by the Los Alamos National Laboratory. On October 27, 2009, the NMPRC decided to initiate an investigation and ordered the Company to respond no later than November 16, 2009. The Company filed an initial response on November 16, 2009 and a supplemental response on January 8, 2010 after obtaining data on which the report was based. The Company responses provided evidence that the reliability and power quality performance for the Company’s service territory as a whole and on the Santa Teresa circuits in particular meet all applicable reliability standards and comport with good utility practices. On January 28, 2010, the NMPRC Staff filed its reply stating that they found no factual basis to conclude that the Company has violated NMPRC rules by not following good utility practices regarding service quality to the customers in the Santa Teresa Industrial Park area and recommended the NMPRC dismiss this proceeding. The Company is unable at this time to predict the ultimate outcome of this docket.
Federal Regulatory Matters
Transmission Dispute with Tucson Electric Power Company (“TEP”). In January 2006, the Company filed a complaint with the FERC to interpret the terms of a Power Exchange and Transmission Agreement (the “Transmission Agreement”) entered into with TEP in 1982. TEP filed a complaint with the FERC one day later raising virtually identical issues. TEP claimed that, under the Transmission Agreement, it was entitled to up to 400 MW of firm transmission rights on the Company’s transmission system that would enable it to transmit power from the Luna Energy Facility (“LEF”) located near Deming, New Mexico to Springerville or Greenlee in 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 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, and hearings on the disputed issues were held before an administrative law judge. In the initial decision dated September 6, 2007, the administrative law judge found that the Transmission Agreement allows TEP to transmit power from the LEF to Arizona but limits that transmission to 200 MW on any segment of the circuit and to non-firm service on the segment from Luna to Greenlee. The Company and TEP filed exceptions to the initial decision.
On November 13, 2008, the FERC issued an order on the initial decision finding that the transmission rights given to TEP in the Transmission Agreement are firm and are not restricted for transmission of power from Springerville as the receipt point to Greenlee as the delivery point. Therefore, pursuant to the order, TEP can use its transmission rights granted under the Transmission Agreement to transmit power from the LEF to either Springerville or Greenlee so long as it transmits no more than 200 MW over all segments at any one time. The FERC also ordered that the Company refund to TEP all sums with interest that TEP had paid it for transmission under the applicable transmission service agreements since February 2006 for service relating to the LEF. On December 3, 2008 the Company refunded $9.7 million to TEP. The Company had established a reserve for the rate refund of
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approximately $7.2 million as of September 30, 2008, resulting in a pre-tax charge to earnings of approximately $2.5 million in 2008. The Company also paid TEP interest on the refunded balance of approximately $0.9 million, which was also charged to earnings in 2008. The Company filed a request for rehearing of the FERC’s decision on December 15, 2008, seeking reversal of the order on the merits and a return of any refunds made in the interim, as well as compensation for all service that the Company may provide to TEP from the LEF over the Company’s transmission system on a going forward basis. The FERC suspended the period for ruling on the motion for rehearing on January 14, 2009. If the FERC denies the Company’s request for rehearing or again finds against the Company on rehearing, the Company will have the right to seek judicial review of the order. If the order is not reversed, the Company will lose the opportunity to receive compensation from TEP for such transmission service in the future. The Company cannot predict the outcome of such potential future proceedings.
In an ancillary proceeding, TEP filed a lawsuit in the United States District Court for the District of Arizona in December 2008, seeking reimbursement for amounts TEP paid a third party transmission provider for purchases of transmission capacity between April 2006 and May 2007, allegedly totaling approximately $1.5 million, plus accrued interest. TEP alleges that the Company was obligated to provide TEP with that transmission capacity without charge under the Transmission Agreement. In September 2009, the Court granted a stay in this suit pending a resolution of the underlying FERC proceeding and any appeal thereof. The Company cannot predict the outcome of this matter.
Pollution Control Bond Refunding. On April 4, 2008, the Company filed an application with the FERC requesting authority for long-term securities transactions necessary to refund and reissue the Company’s Series B and Series C PCBs. The FERC issued an order on May 1, 2008, granting authority for the securities transactions. On March 26, 2009, the Company completed a refunding transaction related to an aggregate principal amount of $100.6 million in pollution control indebtedness. See Note H.
RTOs. FERC’s rule on RTOs (“Order 2000”) strongly encourages, but does not require, public utilities to form and join regional transmission organizations (“RTOs”). The Company is an active participant in the development of WestConnect. The Company has entered into a memorandum of understanding with thirteen other transmission owners that obligates the parties to participate in and commit resources to ongoing joint efforts, including involvement with stakeholders, customers, local, state and federal regulatory personnel, and other western grid transmission providers to identify, develop and implement cost-effective wholesale market enhancements on a voluntary, phased-in basis to add value in transmission accessibility, wholesale market efficiency and reliability for wholesale users of the western grid. These enhancements may ultimately include formation of an RTO. WestConnect will continue to work with the FERC and two other proposed RTOs in the west to achieve a seamless market structure. The Company comprises approximately 6% of WestConnect and cannot control the terms or timing of its development. WestConnect as an RTO will not be operational for several years, if it is achieved at all.
On February 10, 2009, the FERC accepted a participation agreement submitted by nine WestConnect participants establishing the WestConnect Point-to-Point Regional Transmission Service Experiment (the “Proposal”). The FERC also conditionally accepted (subject to the participants making
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minor compliance filings) associated regional transmission tariffs that implement the Proposal for a two-year period. The Proposal calls for participants to offer customers the option of buying hourly non-firm, point-to-point transmission service across their collective transmission systems at a single rate. Taking coordinated service under the proposal is an alternative to pancaked point-to-point transmission service offered under each member’s individual Open Access Transmission Tariff. Participation in the Proposal has not had a material impact on transmission revenues.
Department of Energy. The DOE regulates the Company’s exports of power to the Comisión Federal de Electricidad 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 D - Palo Verde - 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.
Sales for Resale
The Company entered into a contract on April 18, 2007, as amended on August 29, 2008, March 31, 2009 and May 8, 2009, to sell up to 100 MW of firm energy and 50 MW of contingent energy to Imperial Irrigation District (“IID”) beginning May 1, 2007, and continuing through October 31, 2009. The contract also provides for the Company to sell up to 100 MW firm energy and 40 MW of contingent energy beginning November 1, 2009 through April 30, 2010. To ensure that power is available to meet the IID contract demand, the Company entered into a contract effective May 1, 2007, as amended and restated on September 3, 2008 and March 30, 2009, to purchase up to 100 MW of firm energy from Credit Suisse Energy, LLC. This contract provides for up to 100 MW of firm energy to be delivered at Palo Verde through April 30, 2010, and 50 MW of energy delivered at Four Corners in the months of July through September 2007 and May through September for the years 2008 through 2010.
The Company provides firm capacity and associated energy to the RGEC pursuant to an ongoing contract which requires a two-year notice to terminate. The Company also provides network integrated transmission service to RGEC pursuant to the Company’s Open Access Transmission Tariff (“OATT”). In 2006, the Company provided RGEC with a notice of termination. On March 28, 2008, the Company filed with FERC a power sales agreement for full requirements wholesale electric service (the “Agreement”) to sell capacity and energy to RGEC at a cost-based formula rate. The Company requested that the Agreement become effective April 1, 2008 to replace the power sales agreement that expired March 31, 2008. The Agreement includes a formula-based rate that will be updated annually to recover non-fuel generation costs and a fuel adjustment clause designed to recover all eligible fuel and purchased power costs allocable to RGEC. An order accepting the tariff was issued on May 21, 2008 approving the effective date of April 1, 2008.
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C. Regulatory Assets and Liabilities
The Company’s operations are regulated by the PUCT, the NMPRC and the FERC. Regulatory assets represent probable future recovery of previously incurred costs, which will be collected from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are to be credited to customers through the ratemaking process. Regulatory assets and liabilities reflected in the Company’s consolidated balance sheets are presented below (in thousands):
(a) Two year amortization period per NMPRC Case No. 09-00171-UT.
(b) This item is included in rate base which earns a return on investment.
(c) Three year amortization period per NMPRC Case No. 09-00171-UT.
(d) The amortization period for this asset is based upon the life of the associated assets.
(e) This asset is recovered through a recovery factor after expenses are incurred.
(f) Amortization period will be established in PUCT Docket No. 37690.
(g) No specific return on investment is required since related assets and liabilities, including accumulated deferred income taxes and reclamation liability, offset.
(h) This item is excluded from rate base.
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D. 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, 2009 (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 $4.5 million, $4.1 million and $3.3 million for 2009, 2008 and 2007, 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.
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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 inventories, at December 31, 2009 and 2008 is as follows (in thousands):
Palo Verde
The operation of Palo Verde and the relationship among the Palo Verde Participants is governed by the Arizona Nuclear Power Project Participation Agreement (the “ANPP Participation Agreement”). 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 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.
Decommissioning. Pursuant to the ANPP Participation Agreement and federal law, the Company must fund its share of the estimated costs to decommission Palo Verde Units 1, 2 and 3, including the Common Facilities, through the term of their respective operating licenses. The Company is required to maintain a minimum accumulation and a minimum funding level in its decommissioning account at the end of each annual reporting period during the life of the plant. The Company has established external trusts with an independent trustee which enables the Company to record a current
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deduction for federal income tax purposes for most of the amounts funded. At December 31, 2009, the Company’s decommissioning trust fund had a balance of $135.4 million and the Company was above its minimum funding level. The Company will continue to monitor the status of its decommissioning funds and adjust its deposits, if necessary, to remain at or above its minimum accumulation requirements in the future.
Decommissioning costs are estimated every three years based upon engineering cost studies performed by outside engineers retained by APS. On March 26, 2008, the Palo Verde Participants approved the 2007 Palo Verde decommissioning study (the “2007 Study”). The 2007 Study estimated that the Company must fund approximately $324.4 million (stated in 2007 dollars) to cover its share of decommissioning costs which was a reduction in decommissioning costs from the 2004 Palo Verde decommissioning study (the “2004 Study”) and will result in lower asset retirement obligations and lower expenses in the future. Although the 2007 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. See “Spent Fuel Storage” and “Disposal of Low-Level Radioactive Waste” below.
Spent Fuel Storage. The original spent fuel storage facilities at Palo Verde had sufficient capacity to store all fuel discharged from normal operation of all three Palo Verde units through 2003. Alternative on-site storage facilities and casks have been constructed to supplement the original facilities. In March 2003, APS began removing spent fuel from the original facilities as necessary, and placing it in special storage casks which will be stored at the new facilities until accepted by the DOE for permanent disposal. The 2007 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 current 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. In November 1997, the United States Court of Appeals for the District of Columbia Circuit issued a decision preventing the DOE from excusing its own delay but refused to order the DOE to begin accepting spent nuclear fuel. The Company cannot predict when spent fuel shipments to the DOE 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
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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. On February 28, 2007, APS served on the U.S. Department of Justice its “Initial Disclosure of Claimed Damages” of $93.4 million (the Company’s portion being $14.8 million). This amount includes expenses associated with design, construction, loading, and operation of the Palo Verde independent spent fuel storage installation through December 2006. This amount represents costs incurred to ensure sufficient storage capacity for Palo Verde spent fuel that would not have been incurred had the DOE complied with its standard contract obligation to begin accepting spent fuel from the commercial nuclear power industry beginning in 1998. A trial was held for this case in 2009. The Court has not indicated when it will reach a decision in the matter.
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. The construction and opening of low-level radioactive waste disposal sites has been delayed due to extensive public hearings, disputes over environmental issues and review of technical issues related to the proposed sites. The opposition, delays, uncertainty and costs that have been experienced demonstrate possible roadblocks that may be encountered when Arizona seeks to open its own waste repository. APS currently believes that interim low-level waste storage methods are or will be available to allow each Palo Verde unit to continue to operate and to store safely low-level waste until a permanent disposal facility is available.
Reactor Vessel Heads. In accordance with applicable NRC requirements, APS conducts regular inspections of reactor vessel heads at Palo Verde Units 1, 2 and 3. In an effort to reduce long-term operating costs at the station related to inspection of the reactor heads, related equipment, and possible repair costs, APS is replacing reactor vessel heads at Palo Verde. The replacement of the Unit 2 reactor vessel head was successfully completed during the fall 2009 refueling outage. Reactor vessel head replacement is scheduled to occur at Units 1 and 3 in 2010. The Company’s share of the cash requirements for this project is estimated to be $21.1 million of which $11.9 million had been expended at December 31, 2009.
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 $12.6 billion. This potential liability is covered by primary liability insurance provided by commercial insurance carriers in the amount of $375 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 $117.5 million, subject to an annual limit of $17.5 million. 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 $55.7 million, with an annual payment limitation of approximately $8.3 million.
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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 $10.6 million for the current policy period.
E. Accounting for Asset Retirement Obligations
The Company complies with FASB guidance for asset retirement obligations (“ARO”). This guidance 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 also complies with FASB guidance for conditional asset retirements which primarily affects 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. The Company’s AROs 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. The Company records the increase in the ARO due to the passage of time as an operating expense (accretion expense). If the Company incurs or assumes any liability in retiring any asset at the end of its useful life without a legal obligation to do so, it will record such retirement costs as incurred.
The ARO liability for Palo Verde is based upon the estimated cost of decommissioning the plant from the 2007 Palo Verde decommissioning study. See Note D. The ARO liability is calculated by adjusting the estimated decommissioning costs for spent fuel storage and a profit margin and market-risk premium factor. The resulting costs are escalated over the remaining life of the plant and finally discounted using a credit-risk adjusted discount rate. The Company assumed an escalation rate of 3.6%. Since the 2007 Palo Verde decommissioning cost estimate is less than the original estimate in 2007 dollars, the Company used the credit-risk adjusted discount rate of 9.5% used in the original calculation of the ARO liability. 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. Because the DOE is obligated to assume 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, 2009 is $135.4 million.
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FASB guidance 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 2007 study reflected a downward revision in the estimated cash flows for decommissioning costs from the 2004 study, the Company recorded an $8.6 million reduction to its ARO asset and liability in the first quarter of 2008. Accretion and depreciation expense related to the ARO decreased approximately $1.3 million annually as a result of this adjustment.
A reconciliation of the Company’s ARO liability recorded is as follows (in thousands):
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.
F. 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 Plan
On May 2, 2007, the Company’s shareholders approved a stock-based long-term incentive plan (the “2007 LTIP”) and authorized the issuance of up to one million shares of common stock for the benefit of directors and employees. Under the 2007 LTIP, 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, performance stock, cash-based awards and other stock-based awards. 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 the 2007 LTIP. As discussed in Note A,
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the Company accounts for its stock-based long-term incentive plan under FASB guidance for stock-based compensation.
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 (the “Board”). Stock options have not been granted since 2003.
The following table summarizes the transactions in the Company’s stock options for 2009:
The Company received approximately $3.8 million in cash for the 267,900 stock options exercised in 2009. During 2009, the Company realized $0.5 million in current tax benefits from the exercise of stock options. The intrinsic value of stock options exercised in 2009, 2008 and 2007 was $1.5 million, $1.0 million and $5.2 million, respectively. The fair value at grant date of options vested during 2008 and 2007 was $0.1 million and $0.8 million, respectively. No options were forfeited, vested or expired during 2009.
As of January 2, 2008, all 465,888 options outstanding had vested. No compensation cost was recognized in 2008 and 2009 for stock options and there is no unrecognized compensation expense related to stock options. The Company recorded compensation costs of less than $0.1 million in 2007 related to the outstanding unvested stock option awards. The tax benefit and capitalized costs related to these compensation costs in 2007 were less than $0.1 million.
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 three years. The market value of the unvested restricted stock at the date of grant is amortized to expense over the restriction period net of anticipated forfeitures.
Approximately $1.5 million, $1.4 million and $1.7 million was charged to expense related to restricted stock awards in 2009, 2008 and 2007, respectively. The deferred tax benefit related to these expenses was $0.6 million, $0.5 million, and $0.7 million for 2009, 2008 and 2007, respectively. Current tax expense of $0.2 million and $0.1 million was recognized by the Company in 2009 and 2008
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from the issuance of restricted stock, respectively. The Company realized $0.2 million of current tax benefits from the issuance of restricted stock in 2007. 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 2009, 2008 and 2007 was $1.3 million, $1.6 million and $2.0 million, respectively. The fair value at grant date for restricted stock vested in 2009, 2008 and 2007 was $1.7 million, $1.8 million and $1.4 million, respectively. The outstanding restricted stock has remaining $1.3 million of unrecognized compensation expense at December 31, 2009 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 147,427 outstanding restricted shares at December 31, 2009 was $3.0 million.
The following table summarizes the unvested restricted stock transactions for 2009:
The weighted average fair values per share at grant date for restricted stock awarded during 2009, 2008 and 2007 were $14.59, $20.05 and $26.39, 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 between 0% to 200% of performance share awards. Performance shares vesting on January 1, 2009 did not meet the minimum payout threshold and no shares were issued. Performance shares vesting on January 1, 2010 met the 30% payout level and 9,525 shares were issued with a total cost of $0.7 million which had been expensed ratably between 2006 and 2008. The requisite service period for these shares ended December 31, 2009, and the shares had an aggregate intrinsic value of $0.2 million. On January 1, 2011 and 2012, subject to meeting certain performance criteria, performance shares could be awarded. In accordance with FASB guidance related to stock-based compensation, the Company
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recognizes the related compensation expense by ratably amortizing the grant date fair value of awards over the requisite service period and the compensation expense is only adjusted for forfeitures. The actual number of shares issued can range from zero to 320,700 shares.
The fair value at the date of each separate grant 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 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 $1.0 million of unrecognized expense at December 31, 2009 that is expected to be recognized over the weighted average remaining contractual term of the awards of approximately 1 year. The aggregate intrinsic value of the 192,100 outstanding awards (based on 100% performance level) at December 31, 2009 was $3.9 million. The weighted average per share grant date fair value per share of performance shares awarded during the years 2009, 2008 and 2007 was $12.00, $17.14, and $22.78, respectively. The fair value of performance shares which vested in 2008 and 2007 was $0.8 million and $0.7 million, respectively, with an intrinsic value of $0.9 million and $1.0 million, respectively.
The Company recorded compensation expense related to performance shares of $0.7 million, $0.8 million and $0.4 million in 2009, 2008 and 2007, respectively. The compensation expense for 2009, 2008 and 2007 included cumulative adjustments for forfeiture of performance share awards by certain executives. Deferred tax expense related to compensation expense in 2009 and 2008 was $0.3 million and in 2007 was $0.1 million.
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Common Stock Repurchase Program
Since the inception of the stock repurchase program in 1999, the Company has repurchased a total of approximately 21.1 million shares of its common stock at an aggregate cost of $303.4 million, including commissions. During 2009, 1,320,384 shares were repurchased in the open market at an aggregate cost of $24.1 million, including commissions. As of December 31, 2009, the Company had 200,982 shares remain authorized for repurchase under its authorized program. On February 19, 2010, the Board of Directors authorized an additional repurchase of up to 2 million shares of the Company’s outstanding common stock. The Company may in the future make purchases of its common stock pursuant to its authorized program in open market transactions at prevailing prices and may engage in private transactions where appropriate. The repurchased shares will be available for issuance under employee benefit and stock incentive plans, or may be retired.
Basic and Diluted Earnings Per Share
Effective January 1, 2009, the Company adopted FASB guidance which requires a public entity to include share-based compensation awards that qualify as participating securities in both basic and diluted earnings per share to the extent they are dilutive. A share-based compensation award is considered a participating security if it receives non-forfeitable dividends or may participate in undistributed earnings with common stock. The Company awards unvested restricted stock which qualifies as a participating security. The basic earnings per share for the year ended December 31, 2008 was unchanged after adopting the new FASB guidance, however, the diluted earnings per share decreased by $0.01. The basic and diluted earnings per share for the year ended December 31, 2007 were unchanged after adopting the new FASB guidance. The basic and diluted earnings per share are presented below:
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The calculation of the weighted average number of common shares and dilutive potential shares outstanding for the year ended December 31, 2009, 2008 and 2007 excludes 66,628, 50,748 and 55,460 shares, respectively, of restricted stock awards because their effect was antidilutive.
Performance shares of 161,842, 122,479 and 28,172 were excluded from the computation of diluted earnings per share for the year ended December 31, 2009, 2008 and 2007, respectively, as no payments would be required based upon current performance. These amounts assume a 100% performance level payout.
Stock options of 53,610 were excluded from the computation of diluted earnings per share for the year ended December 31, 2009 as the exercise price was greater than the average stock price for the period. No options were excluded from the computation of diluted earnings per share in 2008 and 2007.
G. Accumulated Other Comprehensive Income (Loss)
Accumulated other comprehensive income (loss) consists of the following components (in thousands):
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H. Long-Term Debt and Financing Obligations
Outstanding long-term debt and financing obligations are as follows:
(1) Pollution Control Bonds (“PCBs”)
The Company has four series of tax exempt PCBs in an aggregate principal amount of approximately $193.1 million. The 2005 Series A $59.2 million bonds which mature in 2040, have a fixed interest rate of 4.80% and an effective interest rate of 5.27% after considering related insurance and issuance costs. The 2002 Series A $33.3 million pollution control bonds bear a fixed interest rate of 4.00% until August 1, 2012 when 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.
On March 26, 2009, the Company completed a refunding transaction whereby the 2005 Series B $63.5 million bonds and the 2005 Series C $37.1 million bonds were refunded and replaced by 2009 Series A bonds in the aggregate principal amount of $63.5 million (the “2009 Series A Bonds”) and 2009 Series B bonds in the aggregate principal amount of $37.1 million (the “2009 Series B Bonds”). The 2009 Series A Bonds and the 2009 Series B Bonds were issued as unsecured obligations and both have a fixed interest rate of 7.25%. The 2009 Series A Bonds will mature on
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February 1, 2040 and have an effective interest rate of 7.42% after considering related issuance costs. The 2009 Series B Bonds will mature on April 1, 2040 and have an effective interest rate of 7.42% after considering related issuance costs. The 2005 Series B $63.5 million and the 2005 Series C $37.1 million bonds, which were to mature in 2040, had variable interest rates that were repriced weekly. The Company experienced increased yields and resulting interest expense for the auction rate PCBs as a consequence of the financial market conditions in 2008 and 2009.
(2) Senior Notes
The Company filed a shelf registration statement on Form S-3 with the Securities and Exchange Commission (the “SEC”) which became effective in May 2005 (the “2005 Shelf Registration Statement”). The shelf registration statement enabled 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 under the 2005 Shelf Registration Statement. The proceeds from the issuance of the 6% Senior 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.
The Company filed an automatically-effective Shelf Registration Statement with the SEC on May 20, 2008 (the “WKSI Shelf Registration Statement”). This registration statement enables the Company to offer debt securities, first mortgage bonds, shares of stock and certain other securities in unspecific amounts from time to time in one or more offerings.
In June 2008, the Company issued $150.0 million aggregate principal amount of its 7.5% Senior Notes due March 15, 2038 under the WKSI Shelf Registration Statement. Proceeds from the issuance of the 7.5% Senior Notes of $148.7 million ($150 million principal amount net of a $1.3 million discount) were used to repay short-term borrowings of $44.0 million. The remaining proceeds were used to fund capital expenditures and for other general corporate purposes. The Senior Notes are unsecured obligations of the Company. They were issued pursuant to bond covenants that provide limitations on the Company’s ability to enter into certain transactions.
(3) Nuclear Fuel and Working Capital Financing
The Company has available a $200 million credit facility with a five-year term ending April 2011. The credit facility provides for up to $120 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 0.79% as of December 31, 2009.
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The $200 million credit facility requires compliance with certain total debt and interest coverage ratios. The Company was in compliance with these requirements throughout 2009. No amounts were outstanding under this facility for working capital needs as of December 31, 2009.
As of December 31, 2009, the scheduled maturities for the next five years of long-term debt are as follows (in thousands):
Future obligations and maturities related to nuclear fuel financing obligations estimated to be paid in 2010 are $41.7 million. An estimated $65.3 million will mature during 2011 through 2014. Specific maturity dates are not known, as maturities occur as fuel is burned.
I. Income Taxes
The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and liabilities at December 31, 2009 and 2008 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 deferred tax assets will be fully realized at current levels of book and taxable income.
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The Company recognized income taxes as follows (in thousands):
Current federal income tax expense for 2008 and 2007 reflect taxes accrued under the alternative minimum tax (“AMT”). Deferred federal income tax for 2008 and 2007 includes an offsetting AMT benefit of $8.1 million and $7.1 million, respectively. There was no offsetting AMT benefit for 2009.
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):
As of December 31, 2009, the Company had $28.3 million of AMT credit carryforwards that have an unlimited life.
The Company files income tax returns in the U.S. federal jurisdiction and in the states of Texas, New Mexico and Arizona. The Company is no longer subject to tax examination by the taxing authorities in the federal jurisdiction for years prior to 2007 and in the state jurisdictions for years prior to 1998. On January 6, 2010, the Company reached a settlement with the IRS for the years 2005 and 2006. In the settlement of the tax years 2005 and 2006, the Company agreed with the IRS to the tax treatment for the steam generators in the same manner as settled in the 1999 through 2004 audit which is
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the deduction in the year incurred of 40% of payments related to the repair of the Palo Verde steam generators and the capitalization and depreciation of the remaining 60% of those payments. The IRS settlement affected the timing of these deductions but not their ultimate deductibility for federal tax purposes. A deficiency notice relating to the Company’s 1998 through 2003 income tax returns in Arizona contests a pollution control credit, a research and development credit and the sales and property apportionment factors. The Company is contesting these adjustments.
FASB guidance 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. In January 2010, the Company filed for a change of accounting method with the IRS related to the way in which units of property are determined for purposes of determining capitalized tax assets. The amount of the change is estimated in 2009 deferred taxes prior to recognition of the effects of the accounting change in the 2009 federal income tax return. An unrecognized tax position may be recognized after the IRS audits the 2009 tax return. An amount of any unrecognized tax position cannot be estimated at this time. A reconciliation of the December 31, 2009 and December 31, 2008 amount of unrecognized tax benefits is as follows (in millions):
If recognized, $0.6 million of the unrecognized tax position at December 31, 2009, would affect the effective tax rate. The Company recognized income tax expense for an unrecognized tax position of $0.1 million for the year ended December 31, 2009.
The Company recognizes in tax expense interest and penalties related to tax benefits that have not been recognized. During the years ended December 31, 2009 and 2008, the Company recognized benefits of approximately $0.2 million and $0.9 million, respectively, in interest. In 2007, the Company recognized expense of approximately $0.7 million in interest. The Company had approximately $0.2 million and $0.5 million for the payment of interest and penalties accrued at December 31, 2009 and December 31, 2008, respectively.
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J. Commitments, Contingencies and Uncertainties
Federal Regulatory Matters
See Note B - Federal Regulatory Matters - Transmission Dispute with Tucson Electric Power Company, for discussion of FERC’s initial decision finding in the Company’s transmission dispute with TEP.
Power Contracts
The Company had entered into the following significant agreements with various counterparties for forward firm purchases and sales of electricity:
(1) Purchase agreement modified in 2008 to allow purchase of 125 MW from December 2008 through December 2010.
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. The Company received notice from SPS in late 2006 that SPS had been subject to adverse regulatory action by the PUCT regarding transactions under the contract and that SPS wished to exercise its right to terminate the contract early. As a result on January 29, 2008, the Company and SPS entered into an amendment to the contract and the contract terminated on September 30, 2009.
The Company initiated a Power Purchase and Sale Agreement with Phelps Dodge Energy Services LLC (“Phelps Dodge”) in June 2006. The contract provides for Phelps Dodge to deliver energy to the Company from its ownership interest in the Luna Energy Facility (a 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 Greenlee, Arizona. The Company may purchase up to 100 MW at a specified price at times when energy is not exchanged under the Power Purchase and Sale Agreement. Upon mutual agreement, the contract allows the parties to increase the amount of energy that is purchased and sold under the Power Purchase and Sale Agreement. The parties have agreed to increase the amount to 125 MW for a period of 25 months beginning December 1, 2008. The contract was approved by the FERC and continues through December 31, 2021.
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The Company entered into a contract on April 18, 2007 (as amended on August 29, 2008, March 31, 2009 and May 8, 2009) to sell up to 100 MW of firm energy and 50 MW of contingent energy to Imperial Irrigation District (“IID”), which began May 1, 2007 and continues through October 31, 2009. The contract also provides for the Company to sell up to 100 MW firm energy and 40 MW of contingent energy beginning November 1, 2009 through April 30, 2010. To ensure that power is available to meet the IID contract demand, the Company entered into a contract effective May 1, 2007 (as amended and restated on September 3, 2008 and March 30, 2009) to purchase up to 100 MW of firm energy from Credit Suisse Energy, LLC. This contract provides for up to 100 MW of firm energy to be delivered at Palo Verde through April 30, 2010, and 50 MW of contingent energy delivered at Four Corners in the months of July through September 2007 and May through September for the years 2008 through 2010.
The Company provides firm capacity and associated energy to the RGEC pursuant to an ongoing contract which requires a two-year notice to terminate. The Company also provides network integrated transmission service to RGEC pursuant to the Company’s Open Access Transmission Tariff (“OATT”). In 2006, the Company provided RGEC with a notice of termination. On March 28, 2008, the Company filed with FERC a power sales agreement for full requirements wholesale electric service (the “Agreement”) to sell capacity and energy to RGEC at a cost-based formula rate. The Company requested that the Agreement become effective April 1, 2008 to replace the power sales agreement that expired March 31, 2008. The Agreement includes a formula-based rate that will be updated annually to recover non-fuel generation costs and a fuel adjustment clause designed to recover all eligible fuel and purchased power costs allocable to RGEC. An order accepting the tariff was issued on May 21, 2008 approving the effective date of April 1, 2008.
The Company entered into an agreement to purchase capacity and unit contingent energy from Shell Energy North America (“Shell”). Under the agreement, the Company provides natural gas to Pyramid Unit No. 4 where Shell has the right to convert natural gas to electric energy. The Company may schedule up to 100% of Pyramid Unit No. 4’s output, approximately 40 MW, from January 1, 2010 through December 31, 2010.
The Company entered into a 20-year contract with New Mexico SunTower, LLC (“eSolar”) on October 17, 2008. The contract is a power purchase agreement for the full capacity of a 92 MW concentrated solar plant to be built in Southern New Mexico. The plant is scheduled for commercial operation in 2011.
Environmental Matters
Environmental Regulation. 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
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facility modifications. Failure to comply with these environmental regulatory requirements can result in actions by regulatory agencies or other authorities that might seek to impose on the Company administrative, civil and/or criminal penalties. In addition, unauthorized releases of pollutants or contaminants into the environment can result in costly cleanup obligations that are subject to
enforcement by regulatory agencies. These laws and regulations are subject to change and, as a result of those changes, the Company may face additional capital and operating costs to comply.
Another way in which environmental matters may impact the Company’s operations and business is the implementation of the U.S. Environmental Protection Agency’s (“EPA”) Clean Air Interstate Rule (“CAIR”) which, as applied to the Company, may result in a requirement that it substantially reduce emissions of nitrogen oxides from its power plants in Texas and/or purchase allowances representing other parties’ emissions reductions starting in 2009. These requirements become more stringent in 2015, and are anticipated to require even further emissions reductions or additional allowance purchases. On July 11, 2008, the U.S. Court of Appeals for the District of Columbia vacated CAIR in its entirety. On December 23, 2008 the Court of Appeals granted rehearing and instead remanded CAIR without vacating the original regulation. As a result, the Company must comply with CAIR as written until the EPA rewrites the CAIR rule as required by the Court’s final opinion. The 2009 reconciliation to comply with CAIR is due March 2010 and the Company had accrued $0.5 million at December 31, 2009 to purchase the estimated credits needed to meet its requirement.
Regulations governing the emission of greenhouse gases, such as carbon dioxide, could impact the Company. The U.S. Congress is considering new legislation to restrict or regulate greenhouse gas emissions. The American Clean Energy and Security Act of 2009, which was passed by the U.S. House of Representatives in 2009, could, if enacted by the full Congress, require greenhouse gas emissions reductions by covered sources of as much as 17% from 2005 levels by 2020 and by as much as 83% by 2050. The State of New Mexico, where we operate one facility and have an interest in another facility, has joined with California and several other states in the Western Climate Initiative and is pursuing initiatives to reduce greenhouse gas emissions in the state.
Also, as a result of the U.S. Supreme Court’s decision on April 2, 2007 in Massachusetts, et al. v. EPA, on December 15, 2009, the EPA officially published its finalized determination that emissions of carbon dioxide, methane and other greenhouse gases present an endangerment to human health and welfare because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. Following that determination, the EPA has said it will, in March 2010, finalize regulations under its existing Clean Air Act (“CAA”) authority governing greenhouse gas emissions, including regulating emissions from large stationary sources, such as the fossil fuel-fired power plants operated by the Company, even if Congress does not adopt new legislation specifically addressing emissions of greenhouse gases. In addition, in September 2009, the EPA adopted a new rule requiring approximately 10,000 facilities comprising a substantial percentage of
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annual U.S. greenhouse gas emissions to inventory their emissions starting in 2010 and to report those emissions to the EPA beginning in 2011. The Company’s fossil fuel-fired power generating assets are subject to this rule.
The Company will continue to monitor laws and regulations seeking to limit greenhouse gas emissions. Such laws and regulations have not imposed specific requirements on the Company to date and, as a result, no accrual has been made for potential compliance costs. While the Company strives to prepare for and implement actions necessary to comply with changing environmental regulations, substantial expenditures may be required for the Company to comply with such regulations in the future and, in some instances, those expenditures may be material.
Ongoing Regulatory Compliance. The Company analyzes the costs of its current obligations arising from environmental matters on an ongoing basis and believes it has made adequate provision in its financial statements to meet the obligations which can be meaningfully quantified. As a result of this analysis, the Company has a provision for environmental remediation obligations of approximately $1.2 million as of December 31, 2009, related to compliance with federal and state environmental standards. However, unforeseen expenses associated with environmental compliance or remediation may occur and could have a material adverse effect on the future operations and financial condition of the Company.
The Company incurred the following expenditures to comply with federal environmental statutes (in thousands):
(1) Includes $0.3 million related to alleged excess emissions at the Rio Grande generating station discussed below for the twelve months ended December 31, 2009.
(2) Includes a $0.3 million reserve for remediation costs related to an oil discharge at the Rio Grande generating station discussed below for the twelve months ended December 31, 2009. 2009 also excludes a $0.6 million adjustment reducing estimated remediation costs for a property previously owned by the Company. 2008 includes a $0.2 million reserve for remediation costs for the Gila River Boundary Site discussed below. For 2007 a $0.5 million adjustment was recorded reducing the estimated costs of remediation at the Rio Grande and Copper generating stations.
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
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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 a “potentially responsible party” 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. In November 2009 the Company made an offer to the SESCO working group to settle this matter and a response is pending. 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.
The EPA has investigated releases or potential releases of hazardous substances, pollutants or contaminants at the Gila River Boundary Site, on the Gila River Indian Community (“GRIC”) reservation in Arizona and designated it as a Superfund Site. The Company currently owns 16.29% of the site and will share in the cost of cleanup of this site. The Company has a tentative agreement between the former property owner and the EPA to settle this matter for less than $0.1 million and the Company has accrued $0.2 million for potential costs related to this matter.
On September 30, 2008, the State of New Mexico, acting on behalf of the New Mexico Environment Department (“NMED”), filed a complaint in New Mexico district court alleging that, on approximately 650 occasions between May 2000 and September 2005, the Company’s Rio Grande Power Station, located in Dona Ana County, New Mexico, 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 NMED originally made these allegations in a compliance order which the NMED withdrew simultaneously with the filing of the complaint in district court. On October 27, 2008, the State of New Mexico amended its complaint to allege approximately 300 additional exceedances of permitted nitrogen dioxide and carbon monoxide emission rates and associated reporting failures between October 2005 and July 2007. The amended complaint sought civil penalties in the amount of $15,000 per day for each alleged violation. On July 30, 2009, the Company and NMED entered into a consent decree resolving all issues in this suit. In the consent decree, the Company denied any violations of air emissions standards but agreed to pay a civil penalty of $0.3 million to avoid further defense costs in this matter. In addition, the Company agreed to complete a supplemental environmental project at the Rio Grande Power Station at a cost not to exceed $0.3 million. The New Mexico district court approved the consent decree and dismissed the lawsuit on July 31, 2009.
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In 2006, the Company experienced an oil discharge at the Rio Grande Power Station. The Company remediated the site by removing the contaminated soil and installing monitoring wells to monitor for the presence of hydrocarbons in the ground water. Recently, a monitoring well showed signs of contamination at levels exceeding New Mexico ground water standards. The Company notified the NMED of its findings and submitted an abatement plan to the NMED addressing the soil and ground water impacts. Upon approval of the abatement plan by the NMED, the Company will begin a detailed assessment of the site and perform further remediation of the site as appropriate. The Company has accrued $0.3 million for potential costs related to this matter.
In May 2007, the EPA finalized a new federal implementation plan which addresses emissions at the Four Corners Power Station in northwestern New Mexico of which the Company owns a 7% interest in Units 4 and 5. APS, the Four Corners operating agent, has filed suit against the EPA relating to this new federal implementation plan in order to resolve issues involving operating flexibility for emission opacity standards. The Company cannot predict the outcome of the suit filed against the EPA or whether compliance with the new requirements could have an adverse effect on its capital and operating costs.
On April 6, 2009, APS received a request from the EPA under Section 114 of the CAA seeking detailed information regarding projects and operations at Four Corners. APS has responded to this request. The Company is unable to predict the timing or content of EPA’s response or any resulting actions.
On February 16, 2010, a group of environmental organizations filed a petition with the United States Departments of Interior and Agriculture requesting that the agencies certify to the EPA that emissions from Four Corners are causing “reasonably attributable visibility impairment” under the CAA. APS is currently reviewing the petition and has indicated that it will likely file a response in opposition to the petition. The Company cannot predict the outcome of the petition or whether any resulting actions could have an adverse effect on its capital or operating costs.
In December 2008, El Paso notified the Company that a property purchased from the Company in May 2005 contained subsurface contamination. The Company and El Paso disposed of contaminated materials and in April 2009, the TCEQ notified the parties that no further clean-up was required. The Company’s remediation expense was less than the reserve previously established for this site, and the Company recorded a reduction in environmental expense of $0.6 million in the second quarter of 2009.
Except as described herein, the Company is not aware of any other active investigation of its compliance with environmental requirements by the EPA, the TCEQ or the NMED 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.
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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. In September 2008, a contract was renegotiated with a MiraSol customer resolving all liabilities. As a result of the resolution of all claims, the Company reversed $0.9 million of accrued warranty costs in 2008 and the Company no longer maintains a reserve for warranty claims. Accruals, charges and balances for the reserve for warranty claims for the twelve months ended December 31, 2008 and 2007 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
In February 2008, the Company purchased the executive and administrative office building in El Paso that it had previously leased. All obligations previously incurred relating to this lease were terminated. In June 2008, the Company entered into an agreement to lease land in El Paso adjacent to the Newman Power Station under a lease which expires in June 2033 with a renewal option of 25 years. In addition, the Company leases certain warehouse facilities in El Paso under a lease which expires in December 2014. The Company also has several other leases for office and parking facilities which expire within the next five years.
These 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.
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The Company’s total annual rental expense related to operating leases was $1.1 million, $1.1 million and $2.0 million for 2009, 2008 and 2007, respectively. As of December 31, 2009, the Company’s minimum future rental payments for the next five years are as follows (in thousands):
Union Matters
The collective bargaining agreement with existing union employees expires in September 2010 and the Company anticipates entering into negotiations on a new collective bargaining agreement prior to the expiration of the current contract.
K. 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.
See Note B for discussion of the effects of government legislation and regulation on the Company.
L. 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.
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The Company has two non-qualified retirement 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 plans are based on substantially the same actuarial methods and economic assumptions as those used for the Retirement Plan. On December 15, 2009, the Company adopted FASB guidance on disclosure for pension and other post-retirement plans that requires additional disclosure of investment policies and strategies, categories of investment and fair value measurements of plan assets, and significant concentrations of risk.
The obligations and funded status of the plans are presented below (in thousands):
Amounts recognized in the Company’s consolidated balance sheets consist of the following (in thousands):
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The accumulated benefit obligation for all retirement plans was $202.9 million and $185.7 million at December 31, 2009 and 2008, respectively. The accumulated benefit obligation in excess of plan assets is as follows (in thousands):
Amounts recognized in accumulated other comprehensive income consist of the following (in thousands):
The following are the weighted-average actuarial assumptions used to determine the benefit obligations:
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The components of net periodic benefit cost are presented below (in thousands):
The 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):
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The following are amounts in accumulated other comprehensive income that are expected to be recognized as components of net periodic benefit cost during 2010 (in thousands):
The following are the weighted-average actuarial assumptions used to determine the net periodic benefit cost for the twelve months ended 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 projected cash flows of the benefit plans using the spot rates in the Citigroup Pension Discount Curve and then solving for a single discount rate that produces the same present value of cash flows for each plan. The Company changed its discount rate to determine the benefit obligations for the retirement income plan from 6.10% to 5.90%, the non-qualified retirement plan from 6.30% to 5.20%; and the excess benefit plan from 6.30% to 6.00% at December 31, 2009. For determining 2009 benefit costs, the Company changed its discount rate for the retirement income plan from 6.40% to 6.10%, the non-qualified retirement plan from 6.10% to 6.30% and the excess benefit plan from 6.40% to 6.30%. A 1.0% decrease in the discount rate would increase the 2009 retirement plans’ projected benefit obligation by 14.6%. A 1.0% increase in the discount rate would decrease the 2009 retirement plans’ projected benefit obligation by 11.9%.
The Company’s overall expected long-term rate of return on assets is 7.50% effective January 1, 2010, 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 Company’s target allocations for the plan’s assets are 50% equity securities, 45% fixed income and 5% alternative investments. The Retirement Plan fund includes a diversified portfolio of mutual funds investing in equity securities including large and small capital funds and international funds. The Retirement Plan fund also invests in fixed income securities and real estate. The expected returns for mutual fund
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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.
FASB guidance on disclosure for pension plans requires disclosure of fair value measurements of plan assets. To increase consistency and comparability in fair value measurements FASB guidance on fair value measurements established a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value into three levels as follows:
•
Level 1 - Observable inputs that reflect quoted market prices for identical assets and liabilities in active markets. Prices for securities held in the underlying portfolios of the Retirement Plan are primarily obtained from independent pricing services. These prices are based on observable market data for the same or similar securities.
•
Level 2 - Inputs other than quoted market prices included in Level 1 that are observable for the asset or liability either directly or indirectly. The fair value of the Guaranteed Investment Contract is based on market interest rates of investments with similar terms and risk characteristics.
•
Level 3 - Unobservable inputs using data that is not corroborated by market data. The fair value of the limited real estate partnership is reported at the net asset value of the investment.
The fair value of the Company’s Retirement Plan assets at December 31, 2009, and the level within the three levels of the fair value hierarchy defined by FASB guidance on fair value measurements are presented in the table below (in thousands):
(a) This investment is a commercial real estate partnership that purchases land, develops limited infrastructure, and sells it for commercial development. The Company is restricted from selling its partnership interest during the life of the partnership which is generally 5-7 years. Return of investment is realized as land is sold. There were no sales in 2009. The fair value of the limited partnership interest in real estate is based on the net asset value of the partnership which reflects the appraised value of the land less exit costs.
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The fair value of the investment in the Limited Partnership Interest in Real Estate as of December 31, 2009 resulted in an unrealized loss of $0.6 million for the twelve months ended December 31, 2009. The table below reflects the changes during the period (in thousands):
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 Company contributes at least the minimum funding amounts required by the IRS for the Retirement Plan, as actuarially calculated. The Company expects to contribute $10.2 million to its retirement plans in 2010, although the Company has no 2010 minimum funding requirements for the Retirement Plan.
The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid (in thousands):
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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 PUCT Docket No. 12700. 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 guidance on 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.
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):
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Amounts recognized in the Company’s consolidated balance sheets as a non-current liability consist of accrued postretirement costs of $88.9 million and $85.8 million for 2009 and 2008, respectively.
Amounts recognized in accumulated other comprehensive income that have not been recognized as a component of net periodic cost consist of the following (in thousands):
The following are the weighted-average actuarial assumptions used to determine the accrued postretirement benefit obligations:
Net periodic benefit cost is made up of the components listed below (in thousands):
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The changes in benefit obligations recognized in other comprehensive income are presented below (in thousands):
The total recognized in net periodic benefit cost and other comprehensive income are presented below (in thousands):
The amount in accumulated other comprehensive income that is expected to be recognized as a component of net periodic benefit cost during 2010 is a prior service benefit of $2.9 million.
The following are the weighted-average actuarial assumptions used to determine the net periodic benefit cost for the twelve months ended December 31:
The discount rate is changed at each measurement date based on projected cash flows of the benefit plans using the spot rates in the Citigroup Pension Discount Curve and then solving for a single discount rate that produces the same present value of cash flows for each plan. At December 31, 2009, the Company changed its discount rate from 6.00% to 5.90% to determine the benefit obligations for the other postretirement benefits plan. For determining 2009 benefit cost, the Company changed its discount rate from 6.50% to 6.00%. A 1.0% decrease in the discount rate would increase the 2009
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accumulated postretirement benefit obligation by 16.4%. A 1.0% increase in the discount rate would decrease the 2009 accumulated postretirement benefit obligation by 13.1%.
For measurement purposes, a 9.0% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2009. The rate was assumed to decrease gradually to 5% for 2017 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 $19.1 million or $15.4 million, respectively. In addition, such a 1% change would increase or decrease the aggregate service and interest cost components of the net periodic benefit cost by $1.8 million or $1.5 million, respectively.
The Company’s overall expected long-term rate of return on assets, on an after-tax basis, is 5.20% effective January 1, 2010. 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 Company’s target allocations for the plan’s assets are 65% equity securities, 30% fixed income and 5% alternative investments. The asset portfolio includes a diversified mix of mutual funds investing in equity securities including large and small capital funds and international funds. The asset portfolio also includes fixed income securities, cash equivalents, and 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.
FASB guidance on disclosure for other post-retirement plans requires disclosure of fair value measurements of plan assets. To increase consistency and comparability in fair value measurements FASB guidance on fair value measurements established a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value into three levels as follows:
•
Level 1 - Observable inputs that reflect quoted market prices for identical assets and liabilities in active markets. Prices for securities held in the underlying portfolios of the Other Post-retirement Benefits Plan are primarily obtained from independent pricing services. These prices are based on observable market data for the same or similar securities.
•
Level 2 - Inputs other than quoted market prices included in Level 1 that are observable for the asset or liability either directly or indirectly. The fair value of municipal securities - tax-exempt are reported at fair value based on evaluated prices that reflect observable market information, such as actual trade information of similar securities, adjusted for observable differences.
•
Level 3 - Unobservable inputs using data that is not corroborated by market data. The fair value of the limited real estate partnership is reported at the net asset value of the investment.
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The fair value of the Company’s Other Post-retirement Benefits Plan assets at December 31, 2009, and the level within the three levels of the fair value hierarchy defined by FASB guidance on fair value measurements are presented in the table below (in thousands):
(a) This investment is a commercial real estate partnership that purchases land, develops limited infrastructure, and sells it for commercial development. The Company is restricted from selling its partnership interest during the life of the partnership which is generally 5-7 years. Return of investment is realized as land is sold. There were no sales in 2009. The fair value of the limited partnership interest in real estate is based on the net asset value of the partnership which reflects the appraised value of the land less exit costs.
The fair value of the investment in the Limited Partnership Interest in Real Estate as of December 31, 2009 resulted in an unrealized loss of $0.1 million for the twelve months ended December 31, 2009. The table below reflects the changes during the period (in thousands):
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 2010.
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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. Annual matching contributions made to the savings plans for the years 2009, 2008 and 2007 were $1.6 million each year.
Annual Short-Term Incentive Plan
The Annual Short-Term Incentive Plan (the “Incentive 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 specified level of earnings per share is not attained, no amounts will be paid under the Incentive Plan. The Company reached the required levels of earnings per share, customer satisfaction, and safety goals for incentive payments of $8.6 million, $5.2 million and $7.0 million for 2009, 2008 and 2007, respectively. The Company has renewed the Incentive Plan in 2010 with similar goals.
M. Franchises and Significant Customers
El Paso Franchise
The Company has a franchise agreement with El Paso, the largest city it serves, through July 31, 2030. The franchise agreement includes a franchise fee of 3.25% of revenues and allows the Company to utilize public rights-of-way necessary to serve its retail customers within El Paso.
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Las Cruces Franchise
In February 2000, the Company and Las Cruces entered into a seven-year franchise agreement with a franchise fee of 2% of revenues for the provision of electric distribution service. Las Cruces exercised its right to extend the franchise for an additional two-year term which ended April 30, 2009 and waived its option to purchase the Company’s distribution system pursuant to the terms of the February 2000 settlement agreement. The Company is currently operating under an implied franchise by satisfying all obligations from the expired franchise.
Military Installations
The Company currently serves Holloman Air Force Base (“Holloman”), White Sands Missile Range (“White Sands”) and Fort Bliss. The Company’s sales to the military bases represent approximately 3% of annual operating revenues. The Company signed a contract with Ft. Bliss in October 2008 under which Ft. Bliss takes retail electric service from the Company. The contract is effective until the later of: (i) August 1, 2010 or (ii) new base rates have been approved for the Company in any Texas rate proceeding. In April 1999, the Army and the Company entered into a ten-year contract to provide retail electric service to White Sands. The contract with White Sands expired in 2009 and the Company is serving White Sands under the applicable New Mexico tariffs. In March 2006, the Company signed a contract with Holloman that provides for the Company to provide retail electric service and limited wheeling services to Holloman for a ten-year term which expires in January 2016.
N. Financial Instruments and Investments
FASB guidance requires the Company to disclose estimated fair values for its financial instruments. The Company has determined that cash and temporary investments, investment in debt securities, 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. Investments in debt securities and decommissioning trust funds are carried at fair value.
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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. The Company entered into treasury rate lock agreements in 2005 to hedge against potential movements in the treasury reference interest rate pending the issuance of the 6% Senior Notes. 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, net of tax, as a component of accumulated other comprehensive loss and amortizes the accumulated comprehensive loss to earnings as interest expense over the life of the 6% Senior Notes. In 2010, 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 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, 2009, 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 FASB guidance for accounting for derivative instruments and hedging activities, and, as such, were not required to be accounted for as derivatives.
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 FASB guidance for accounting for derivative instruments and hedging activities. However, as of December 31, 2009, the variable, market-based pricing provisions of existing gas contracts are such that these derivative instruments have no significant fair value.
EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Marketable Securities. The Company’s marketable securities, included in decommissioning trust funds in the balance sheets, are reported at fair value which was $135.4 million and $111.3 million at December 31, 2009 and 2008, respectively. These securities are classified as available for sale under FASB guidance for certain investments in debt and equity securities and are valued using prices and other relevant information generated by market transactions involving identical or comparable securities. The reported fair values include gross unrealized losses on marketable securities whose impairment the Company has deemed to be temporary. The tables below present the gross unrealized losses and the fair value of these securities, aggregated by investment category and length of time that individual securities have been in a continuous unrealized loss position, at December 31, 2009 and 2008 (in thousands):
(1) Includes approximately 106 securities.
(2) Includes approximately 161 securities.
EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The Company monitors the length of time the security 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 securities until their market price recovers, these securities are considered 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.
The reported fair values also include gross unrealized gains on marketable securities which have not been recognized in the Company’s net income. The table below presents the unrecognized gross unrealized gains and the fair value of these securities, aggregated by investment category at December 31, 2009 and 2008 (in thousands):
The Company’s marketable securities include investments in municipal, corporate and federal debt obligations. The contractual year for maturity of these available-for-sale securities as of December 31, 2009 is as follows (in thousands):
EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The Company has recognized some impairment losses on certain of its securities to be other than temporary and in accordance with FASB guidance, these impairment losses have been recognized in net income and a lower cost basis has been established for these securities. For the twelve months ended December 31, 2009, 2008, and 2007 the Company recognized other than temporary impairment losses on its available-for-sale securities as follows (in thousands):
The Company’s marketable securities in its decommissioning trust funds are sold from time to time and the Company uses the specific identification basis on which to determine the amount to reclassify out of accumulated other comprehensive income and into net income. The proceeds from the sale of these securities during the twelve months ended December 31, 2009, 2008, and 2007 and the related effects on pre-tax income are as follows (in thousands):
Fair Value Measurements. FASB guidance requires the Company to provide expanded quantitative disclosures for financial assets and liabilities recorded on the balance sheet at fair value. Financial assets carried at fair value include the Company’s decommissioning trust investments and investments in debt securities. The Company has no liabilities that are measured at fair value on a recurring basis. The FASB guidance establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value into three levels as follows:
•
Level 1 - Observable inputs that reflect quoted market prices for identical assets and liabilities in active markets. Financial assets utilizing Level 1 inputs include the nuclear decommissioning trust investments in active exchange-traded equity securities and U.S. treasury securities that are in a highly liquid and transparent market.
EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
•
Level 2 - Inputs other than quoted market prices included in Level 1 that are observable for the asset or liability either directly or indirectly. Financial assets utilizing Level 2 inputs include the nuclear decommissioning trust investments in other fixed income securities. The fair value of these financial instruments is based on evaluated prices that reflect observable market information, such as actual trade information of similar securities, adjusted for observable differences.
•
Level 3 - Unobservable inputs using data that is not corroborated by market data and primarily based on internal Company analysis using models and various other analyses. Financial assets utilizing Level 3 inputs include the Company’s investments in debt securities.
As of December 31, 2009, the Company had $4.0 million invested in debt securities which consisted of two $2.0 million investments in auction rate securities maturing in 2042 and 2044. The Company classifies these securities as trading securities. These auction rate securities are collateralized with student loans which are re-insured by the Department of Education as part of the Federal Family Education Loan Program (“FFELP”) and have credit ratings of “A” by Standard & Poors and “A2” by Moody’s. The principal on the securities can be realized at maturity, sold in a successful auction, or sold in the secondary market. Interest rates on the auction rate securities are reset every 28 days. At December 31, 2009 upon a failed auction, the maximum interest rates for $2.0 million of the debt securities were based upon the lesser of the interest paid on the student loan portfolio, less service costs or one month LIBOR plus 2.5%. At December 31, 2009, the default interest rate was 2.731% based on one month LIBOR plus 2.5%. The maximum interest rate for the remaining $2.0 million debt securities were based upon the lesser of (i) the interest paid on the student loan portfolio less service costs; (ii) 91-day Treasury bills plus 1.5%; (iii) one month LIBOR plus 1.5%; (iv) 18%; or (v) highest rate legally payable. At December 31, 2009, the default interest rate was 1.733% based on one month LIBOR plus 1.5%.
The auction process historically provided a liquid market to sell the securities to meet cash requirements. These auction rate securities had successful auctions through January 2008. However, since February 2008, auctions for these securities have not been successful, resulting in the inability to liquidate these investments. The Company’s valuation as of December 31, 2009 is based upon the average of a discounted cash flow model valuation and a market comparables method.
The discounted cash flow model valuation is based on expected cash flows using the maximum expected interest rates discounted by an expected yield reflecting illiquidity and credit risk. In order to more accurately forecast cash flows, treasury and LIBOR yield curves were created using swap rates, data provided on the U.S. Department of the Treasury website and the British Banker’s Association website. After thorough analysis, future cash flows were projected based on interest rate models over a term, which was based on an estimate of the weighted average life of the student loan portfolio within the issuing trusts. The applied discount yield was based on the applicable forward LIBOR rate and a yield spread of 550 basis points based on the securities’ (i) credit risk, (ii) illiquidity, (iii) subordinated status, (iv) interest rate limitations, and (v) FFELP guarantees.
EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The market comparables method is based upon sales and purchases of auction rate securities in secondary market transactions. The secondary market discounts of 36% to 38% are based on discounts indicated in secondary market transactions involving comparable Student Loan Auction Rate Securities. The average of the values provided by the discounted cash flow calculation and the market comparables method are used to arrive at the concluded value of the securities.
The securities in the Company’s decommissioning trust funds are valued using prices and other relevant information generated by market transactions involving identical or comparable securities. FASB guidance identifies this valuation technique as the “market approach” with observable inputs. The Company analyzes available-for-sale securities to determine if losses are other than temporary.
The fair value of the Company’s decommissioning trust funds and investments in debt securities, at December 31, 2009 and 2008, and the level within the three levels of the fair value hierarchy defined by FASB guidance are presented in the table below (in thousands):
EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The change in the fair value of the investments in debt securities resulted in a credit to income of $0.2 million and a charge to income of $1.7 million for the twelve months ended December 31, 2009 and 2008, respectively. The amount is reflected in the Company’s consolidated statement of operations as an adjustment to investment and interest income. Below is a reconciliation of the beginning and ending balance of the fair value in investment in debt securities (in thousands):
(1) Amounts presented as being transferred in are based on the fair value at the beginning of the period.
EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
O. Supplemental Statements of Cash Flows Disclosures
P. 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.
(2) Net income in the fourth quarter of 2008 was reduced by a $2.5 million refund of 2006 transmission wheeling revenues from Tucson Electric Power pursuant to an order of the FERC.
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. Under the supervision and with the participation of our management, including our chief executive officer and our chief financial officer, we have evaluated the effectiveness of the design and operation of our disclosure controls and procedures as defined in Rule 13a-15(e) of the Securities Exchange Act of 1934. These controls and procedures are designed to ensure that material information relating to the company and its subsidiaries is communicated to the chief executive officer and the chief financial officer by others within those entities. Based on that evaluation, our chief executive officer and our chief financial officer concluded that, as of December 31, 2009, our disclosure controls and procedures are effective to ensure that information required to be disclosed by us in reports that we file or submit under the Securities Exchange Act of 1934 is accumulated and communicated to the chief executive officer and the chief financial officer, and recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under the Act is accumulated and communicated to the issuer’s management, including its principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.
Management’s Annual Report on Internal Control Over Financial Reporting. Management’s Annual Report on Internal Control over Financial Reporting is included herein under the caption “Management Report on Internal Control Over Financial Reporting” on page 57 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, 2009, that materially affected, or that were reasonably likely to materially affect, our internal control over financial reporting.
Item 9B.
Item 9B. Other Information
None.
PART III
Item 10.
Item 10. Directors, Executive Officers of the Registrant and Corporate Governance
Information regarding directors is incorporated herein by reference from our definitive proxy statement for the 2010 Annual Meeting of Shareholders (the “2010 Proxy Statement”) under the heading “Nominees 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 2010 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 2010 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 2010 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 2010 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 2010 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 2010 Proxy Statement under the heading “Security Ownership of Certain Beneficial Owners and Management.”
Equity Compensation Plan Information
Item 13.
Item 13. Certain Relationships and Related Transactions, and Director Independence
Incorporated herein by reference from the 2010 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 2010 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 EXHIBITS
INDEX TO EXHIBITS
INDEX TO EXHIBITS
INDEX TO EXHIBITS
INDEX TO EXHIBITS
INDEX TO EXHIBITS
INDEX TO EXHIBITS
INDEX TO EXHIBITS
INDEX TO EXHIBITS
INDEX TO EXHIBITS
INDEX TO EXHIBITS
Exhibit
Number
Title
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.

In lieu of non-employee director cash compensation, eight agreements, dated as of January 1, 2008, April 1, 2008, July 1, 2008 and October 1, 2008, 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, ten agreements, dated as of May 8, 2008, substantially identical in all material respects to this Exhibit, were entered into with J. Robert Brown; James W. Cicconi; George W. Edwards, Jr.; 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 January 1, 2009 and April 1, 2009, 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, twelve agreements, dated as of May 7, 2009, substantially identical in all material respects to this Exhibit, were entered into with Catherine A. Allen; J. Robert Brown; James W. Cicconi; George W. Edwards, Jr.; 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, 2009 and October 1, 2009, substantially identical in all material respects to this Exhibit, have been entered into with Catherine A. Allen; Kenneth R. Heitz; and Patricia Z. Holland-Branch; 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.
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.
INDEX TO EXHIBITS
Exhibit
Number
Title
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 these Exhibits. The copies filed omit the information subject to the confidentiality request. Omissions are designated as “****.” A complete version of these Exhibits has been filed separately with the Securities and Exchange Commission.
UNDERTAKING
Insofar as indemnification for liabilities arising under the Securities Act of 1933 may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act of 1933 and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question of whether such indemnification by it is against public policy as expressed in the Act and will be governed by the final adjudication of such issue.
POWER OF ATTORNEY
KNOW ALL MEN BY THESE PRESENTS, that each of El Paso Electric Company, a Texas corporation, and the undersigned directors and officers of El Paso Electric Company, hereby constitutes and appoints David W. Stevens, David G. Carpenter, Mary E. Kipp 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 26th day of February 2010.
EL PASO ELECTRIC COMPANY
By:
/s/ DAVID W. STEVENS
David W. Stevens
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.