Item 1.
Business
General
El Paso Electric Company (the "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 1,765 MW. For the year ended December 31, 2012, the Company’s energy sources consisted of approximately 46% nuclear fuel, 32% natural gas, 6% coal, 16% purchased power and less than 1% generated by wind turbines.
The Company serves approximately 384,000 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 62% and 12%, respectively, of the Company’s retail revenues for the year ended December 31, 2012). 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 refineries, two large universities, steel production and copper refining 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, 2013, the Company had approximately 1,000 employees, 40% 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
As of December 31, 2012, the Company’s net dependable generating capability of 1,765 MW consists of the following:
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* During summer peak period.
Palo Verde Station
The Company owns an interest, along with six other utilities, in the three nuclear generating units and common facilities (“Common Facilities”) at Palo Verde. Arizona Public Service Company (“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.
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License Extension. In 2011, the NRC renewed the operating licenses for all three units at Palo Verde. The renewed licenses for Units 1, 2 and 3 now expire in 2045, 2046 and 2047, respectively.
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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. In 2011, the Palo Verde Participants approved the 2010 Palo Verde decommissioning study (the “2010 Study”), which reflected the extension of the operating license, and estimated that the Company must fund approximately $357.4 million (stated in 2010 dollars) to cover its share of decommissioning costs. At December 31, 2013, the Company's decommissioning trust fund had a balance of $187.1 million. Although the 2010 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.
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Spent Fuel Storage. 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, but to date has not done so. In 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. In 2010, the court awarded APS and the other Palo Verde Participants approximately $30 million in damages, of which the Company received $4.8 million. On December 19, 2012, APS, acting on behalf of itself and the Palo Verde Participants, filed a second lawsuit against the DOE, seeking to recover damages incurred due to DOE's failure to accept Palo Verde's spent nuclear fuel for the period beginning January 1, 2007 through June 30, 2011.
The DOE had planned to meet its disposal obligations through a permanent geologic repository at Yucca Mountain, Nevada. However, legal proceedings in a variety of jurisdictions, as well as regulatory challenges, have delayed the approval and implementation of this plan. The Company cannot predict when spent fuel shipments to the DOE will commence. APS and the Company believe 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, however the Company expects to incur significant costs for on-site spent fuel storage during the life of Palo Verde, which may be recoverable from the DOE.
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NRC Oversight of the Nuclear Energy Industry in the Wake of the Earthquake and Tsunami in Japan. 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. Following the March 11, 2011 earthquake and tsunami in Japan, which caused significant damage to the Fukushima Daiichi Nuclear Power Station, the NRC launched a two-pronged review of U.S. nuclear power plant safety. With respect to Palo Verde, the NRC issued two orders requiring safety enhancements regarding: (1) mitigation strategies to respond to extreme natural events resulting in the loss of power at plants; and (2) enhancement of spent fuel pool instrumentation. The NRC has also requested information pertaining to re-evaluations of seismic and flooding hazards, communications, and staffing during events affecting multiple reactors at a site. Palo Verde has budgeted $14 million, total project, in modifications for the 2013 capital budget relating to the NRC requirements. Until further action is taken by the NRC as a result of this event, the Company cannot predict any additional financial or operational impacts on Palo Verde.
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Liability and Insurance Matters. The Palo Verde participants have insurance for public liability resulting from nuclear energy hazards, covered by primary liability insurance provided by commercial insurance carriers and 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 up to $55.7 million, with an annual payment limitation of approximately $8.3 million. The Palo Verde Participants also maintain “all risk” (including nuclear hazards) insurance for property damage to, and decontamination of, property at Palo Verde. In addition, the Company has secured insurance against portions of any increased cost of generation or purchased power and business interruption resulting from a sudden and unforeseen outage at Palo Verde.
Fossil-Fueled Plants
The Newman Power Station consists of three steam-electric generating units and two combined cycle generating units. In 2012 the net dependable capability at Newman Power Station was reduced by 20 MW to reflect the exclusion of the duct burners for dependable operation on the Newman Unit 4 combined cycle generating unit. The station operates primarily on natural gas but the conventional steam-electric generating units can also operate on fuel oil.
The Company's Rio Grande Power Station consists of three steam-electric generating units which operate on natural gas. Construction has begun on Rio Grande Unit 9 to add an aeroderivative unit with a net dependable summer peak period generating capacity of 87 MW that should achieve commercial operation by May 2013.
The Company owns a 7% interest in Units 4 and 5 at Four Corners. The Company shares power entitlements and certain allocated costs of the two units with APS (the Four Corners operating agent) and the other Four Corners participants. Four Corners is located on land under easements from the federal government and a lease from the Navajo Nation that expires in 2016. APS, on behalf of the Four Comers participants, negotiated amendments to the lease with the Navajo Nation which extended the lease from 2016 to 2041, pending the approval of the Department of the Interior and a Federal environmental review.
The Company's Copper Power Station consists of a combustion turbine used primarily to meet peak demand.
Hueco Mountain Wind Ranch
The Company’s Hueco Mountain Wind Ranch 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.
In addition to the transmission and distribution lines within our service territory, the Company's transmission network and associated substations include the following:
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(1)
Runs from TEP's Springerville Generating Plant near Springerville, Arizona, to the Company's Diablo Substation near Sunland Park, New Mexico.
(2)
Runs from PNM's West Mesa Substation located near Albuquerque, New Mexico, to the Company's Arroyo
Substation located near Las Cruces, New Mexico.
(3)
Runs from TEP's Greenlee Substation near Duncan, Arizona to the Newman Power Station.
(4) Runs 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.
(5)
Represents two 45-mile, 500 kV lines running from Palo Verde to the Westwing Substation located northwest of Phoenix near Peoria, Arizona.
(6) Runs from Palo Verde to the Jojoba Substation located near Gila Bend, Arizona, then to the Kyrene Substation located near Tempe, Arizona.
Environmental Matters
General. The Company is subject to extensive laws, regulations and permit requirements with respect to air, soil and water quality, waste management and disposal, natural resources and other environmental matters by federal, state, regional, tribal and local authorities. Failure to comply with such laws, regulations and requirements can result in actions by authorities or other third parties that might seek to impose on the Company administrative, civil and/or criminal penalties or other sanctions. In addition, releases of pollutants or contaminants into the environment can result in costly cleanup liabilities. These laws, regulations and requirements are subject to change through modification or reinterpretation, or the introduction of new laws and regulations and, as a result, the Company may face additional capital and operating costs to comply. Certain key environmental issues, laws and regulations facing the Company are described further below.
Air Emissions. The U.S. Clean Air Act ("CAA"), associated regulations and comparable state laws and regulations relating to air emissions impose, among other obligations, limitations on pollutants generated during the Company's operations, including sulfur dioxide ("SO2"), particulate matter ("PM"), nitrogen oxides ("NOx") and mercury.
Clean Air Interstate Rule/Cross State Air Pollution Rule. The U.S. Environmental Protection Agency's ("EPA") Clean Air Interstate Rule ("CAIR"), as applied to the Company, involves requirements to limit emissions of NOx and SO2 from certain of the Company's power plants in Texas and/or purchase allowances representing other parties' emissions reductions since 2009. While the U.S. Court of Appeals for the District of Columbia Circuit voided CAIR in 2008, such appellate court in August 2012 also vacated the EPA’s proposed replacement, called the Cross-State Air Pollution Rule (“CSAPR”). The EPA is expected to propose a CSAPR replacement rule, which if finalized and upheld, would also replace CAIR. The timing and substance of any final CAIR replacement is currently unknown and until promulgated and upheld, the Company remains subject to CAIR. The annual reconciliation to comply with CAIR is due by March 31 of the following year.The Company has purchased allowances and expensed the following costs to meet its annual requirements (in thousands):
National Ambient Air Quality Standards. Under the CAA, the EPA sets National Ambient Air Quality Standards ("NAAQS") for six criteria emissions considered harmful to public health and the environment, including PM, NOx, carbon monoxide ("CO") and SO2. NAAQS must be reviewed by the EPA at five-year intervals. In 2010, the EPA strengthened the NAAQS for both NOx and SO2. In December 2012, the EPA strengthened the NAAQS for fine PM, and it is likely to propose more stringent ozone NAAQS in 2013. The Company continues to evaluate what impact these final and proposed NAAQS could have on its operations. If the Company is required to install additional equipment to control emissions at its facilities, the revised NAAQS could have a material impact on its operations and consolidated financial results.
Utility MACT. The operation of coal-fired power plants, such as the Company's Four Corners plant, results in emissions of mercury and other air toxics. In December 2011, the EPA finalized Mercury and Air Toxics Standards (known as the "Utility MACT") for oil- and coal-fired power plants, which requires significant reductions in emissions of mercury and other air toxics. Several challenges are being made to this rule. These challenges notwithstanding, companies impacted by the new standards will have up to three (and some cases, four) years to comply. Information from the Four Corners plant operator, APS, indicates that APS believes Units 4 and 5 will require no additional modifications to achieve compliance with the Utility MACT standards; however, further testing and evaluation are planned.
Other Laws and Regulations. In addition, Four Corners, is, or may in the future be, required to comply with various other environmental laws and regulations and involved in various other legal proceedings related to such laws and regulations, which compliance and proceedings could result in increased costs to us. For example, Four Corners will be required to install pollution control equipment that constitutes the best available retrofit technology to lessen the impacts of emissions on visibility surrounding the plant, the costs of which could be material.
Climate Change. The U.S. federal government has either considered, proposed and/or finalized legislation or regulations limiting greenhouse gas ("GHG") emissions, including carbon dioxide. In particular, the U.S. Congress is expected to consider legislation to restrict or regulate GHG emissions in the next few years. In the past few years, the EPA began using the CAA to limit carbon dioxide and other GHG emissions, such as the 2009 GHG Reporting Rule and the EPA’s sulfur hexafluoride ("SF6") reporting rule, both of which the Company is subject, as well as the EPA’s 2010 so-called Tailoring Rule which rule could impose significant obligation and costs on power plant owners and operators. During the second term of the Obama Administration, the EPA is expected to propose further regulations targeting GHG emissions, including from existing power plants at some point in the future. In addition, almost half the U.S. states, either individually and/or through multi-state regional initiatives, have begun to consider how to address GHG emissions and have developed, or are actively considering the development of emission inventories or regional GHG cap and trade programs. While 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 more on coal-fired generation, current and future legislation and regulation of GHGs or any future related litigation could impose significant costs and/or operating restrictions on the Company, reduced demand for the power the Company generates and/or require the Company to purchase rights to emit GHGs, any of which could have a material adverse effect on the Company's 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 the Company's 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 believes that material effects on the Company's business or results of 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, the Company believes it is impossible to meaningfully quantify the costs of these potential impacts at present.
Environmental Litigation and Investigations. Since 2009, the EPA and certain environmental organizations have been scrutinizing, and in some cases, have filed lawsuits, relating to certain air emissions and air permitting matters from or of Four Corners. Since July 2011, the U.S. Department of Justice ("DOJ"), on behalf of the EPA, and APS have been engaged in substantive settlement negotiations in an effort to resolve the pending matters. The allegations being addressed through settlement negotiations are that APS failed to obtain the necessary permits and install the controls necessary under the CAA to reduce SO2, NOx, and PM, and that defendants failed to obtain an operating permit under Title V of the CAA that reflects applicable requirements imposed by law. In March 2012, the DOJ provided APS with a draft consent decree to settle the EPA matter, which decree contains specific provisions for the reduction and control of NOx, SO2, and PM, as well as provisions for a civil penalty, and expenditures on environmental mitigation projects with an emphasis on projects that address alleged harm to the Navajo Nation. Settlement discussions are on-going.
Similar to other utilities in the western half of the U.S., the Company received notice that Earthjustice filed a lawsuit in the United States District Court for New Mexico on October 4, 2011 for alleged violations of the Prevention of Significant Deterioration ("PSD") provisions of the CAA related to Four Corners. On January 6, 2012, Earthjustice filed a First Amended Complaint adding claims for violations of the CAA's New Source Performance Standards ("NSPS") program. Among other things, the plaintiffs seek to have the court enjoin operations at Four Corners until APS applies for and obtains any required PSD permits and complies with the referenced NSPSs. The plaintiffs further request the court to order the payment of civil penalties, including a beneficial mitigation project. On April 2, 2012, APS and the other Four Corners' participants filed motions to dismiss with the court. Earthjustice filed their response briefs on May 16, 2012. APS filed reply briefs on June 22, 2012. Utility Air Regulatory Group filed an amicus brief, and plaintiffs were allowed until July 23, 2012 to respond to that amicus brief. In November 2012, the parties filed a joint motion to stay the proceedings to enable settlement discussions, and the motion was granted staying the case until March 2013. The Company is unable to predict the outcome of this litigation.
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 2013 through 2017 are approximately $1.2 billion. Actual costs may vary from the construction program estimates shown. Such estimates are reviewed and updated periodically to reflect changed conditions.
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(1)
Does not include acquisition costs for nuclear fuel. See “Energy Sources - Nuclear Fuel.”
(2)
$325 million has been allocated for new generating capacity including $10 million to complete Rio Grande Unit 9 in 2013. Included in this amount is $98 million to complete construction of two 88 MW gas-fired LMS-100 units that are scheduled to come on line in 2014 and 2015, and $138 million for two additional 88 MW LMS-100 units scheduled to come on line in 2016 and 2017. In addition, $62 million of common costs associated with the development of the new Montana generating station are included in these amounts. Also included is $17 million for a combined cycle unit scheduled to come on line in 2021, $44 million for other local generation, $37 million for the Four Corners Station and $166 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.
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 are continually identifying their future nuclear fuel resource needs and negotiating arrangements to fill those needs. The Palo Verde participants have contracted for 100% of Palo Verde's requirements for uranium concentrates through 2016, 95% of its requirements in 2017 and 80% of its requirements in 2018. The participants have also contracted for all of Palo Verde's conversion services through 2016 and 90% of its requirements in 2017-2018, all of Palo Verde's enrichment services through 2020 and all of Palo Verde's fuel assembly fabrication services through 2016.
Nuclear Fuel Financing. The Company’s financing of nuclear fuel is accomplished through Rio Grande Resources Trust (“RGRT”), a Texas grantor trust, which is consolidated in the Company’s financial statements. RGRT has $110 million aggregate principal amount borrowed through senior notes. The Company guarantees the payment of principal and interest on the senior notes. The nuclear fuel financing requirements of RGRT are met with a combination of the senior notes and amounts borrowed under the revolving credit facility (the “RCF”).
The Company maintains the RCF for the financing of nuclear fuel and for working capital and general corporate purposes. The RCF has a term ending September 2016. On March 29, 2012, the Company increased the aggregate unsecured borrowing available under the RCF from $200 million to $300 million. The total amount borrowed for nuclear fuel by RGRT at December 31, 2012 was $132.2 million of which $22.2 million had been borrowed under the RCF, and $110 million was borrowed through the senior notes. Interest costs on borrowings to finance nuclear fuel are accumulated by RGRT and charged to the Company as fuel is consumed and recovered from customers through fuel recovery charges.
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 2012, 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 2013. 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.
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 mid-2016.
On December 19, 2012, BHP Billiton, the parent company of BNCC, the coal supplier and operator of the mine that serves Four Corners, announced that it has entered into a Memorandum of Understanding with the Navajo Nation setting out the key terms under which full ownership of BNCC would be sold to the Navajo Nation. BHP Billiton would be retained by BNCC under contract as the mine manager and operator until July 2016. A new coal supply contract, which extends the term beyond July 2016, is being negotiated by the Navajo Nation and APS on behalf of the other Four Corners participants. Any new coal supply contract or revisions to the current contract are subject to the approval of all the Four Corners participants.
As a result of this proposed change in ownership of BNCC, the participants are negotiating a new coal supply contract and the endorsement of the transfer of ownership of the stock of BNCC to a new Navajo Nation commercial enterprise to be established by the Navajo Nation Tribal Council is being contemplated. The decision of the Tribal Council is currently expected to occur in the second quarter of 2013.
Purchased Power
To supplement its own generation and operating reserves and to meet required renewable portfolio standards, the Company engages in firm power purchase arrangements which may vary in duration and amount based on evaluation of the Company’s resource needs, the economics of the transactions and specific renewable portfolio requirements.
The Company has a Power Purchase and Sale Agreement with Freeport-McMoran Copper and Gold Energy Services LLC (“Freeport”) which provides for Freeport 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 125 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 through December 2013. The contract was approved by the FERC and continues through December 31, 2021.
The Company entered into an agreement in 2009 to purchase capacity of up to 40 MW and unit contingent energy during 2010 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 entered into a contract with Shell on May 17, 2010 to extend the term of the capacity and unit contingent energy purchase from January 1, 2011 through September 30, 2014.
The Company entered into a 20-year contract with NRG Solar Roadrunner, LLC ("NRG") for the purchase of all of the output of a 20 MW solar photovoltaic plant built in southern New Mexico which began commercial operation in August 2011. The Company has a 25-year purchase power agreement with Hatch Solar Energy Center I, LLC for a 5 MW solar photovoltaic project located in southern New Mexico which began commercial operation in July 2011. The Company has 25-year purchase power agreements to purchase all of the output of two additional solar photovoltaic projects located in southern New Mexico, SunEdison 1 (10 MW) and SunEdison 2 (12 MW) which achieved commercial operation on June 25, 2012 and May 2, 2012, respectively. The Company entered into these contracts to help meet its renewable portfolio requirements.
Other purchases of shorter duration were made during 2012 to supplement 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)
Includes spot sales and net losses of 291,000 kW, 253,000 kW and 273,000 kW for 2012, 2011 and 2010, respectively.
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 (sales for resale) transactions, transmission service and compliance with federally-mandated reliability standards. The decisions of the PUCT, NMPRC and the FERC are subject to judicial review.
Texas Regulatory Matters
2012 Texas Retail Rate Case. The Company filed a rate increase request with the PUCT, Docket No. 40094, the City of El Paso, and other Texas cities on February 1, 2012. The rate filing was made in response to a resolution adopted by the El Paso City Council (the "Council") requiring the Company to show cause why its base rates for customers in the El Paso city limits should not be reduced. The filing at the PUCT also included a request to reconcile $356.5 million of fuel expense for the period July 1, 2009 through September 30, 2011.
On April 17, 2012, the Council approved the settlement of the Company's 2012 Texas retail rate case and fuel reconciliation in PUCT Docket No. 40094. The PUCT issued a final order approving the settlement on May 23, 2012.
Under the terms of the settlement, among other things, the Company agreed to:
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A reduction in its non-fuel base rates of $15 million annually, with the decrease being allocated primarily to Texas retail commercial and industrial customer classes. The rate decrease was effective as of May 1, 2012;
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Revised depreciation rates for the Company's gas-fired generating units and for transmission and distribution plant that lower depreciation expense by $4.1 million annually;
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Continuation of the 10.125% return on equity for the purpose of calculating the allowance for funds used during construction; and
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A two-year amortization of rate case expenses, none of which will be included in future regulatory proceedings.
As part of the settlement, the Company agreed to withdraw its request to reconcile fuel costs for the period from July 1, 2009 through September 30, 2011. The Company will file a fuel reconciliation request covering the period beginning July 1, 2009 and ending no later than June 30, 2013 by December 31, 2013 or as part of its next rate case, if earlier.
Fuel and Purchased Power Costs. The Company's actual fuel costs, including purchased power energy costs, are recoverable from its customers. The PUCT has adopted a fuel cost recovery rule ("Texas Fuel Rule") that allows the Company to seek periodic adjustments to its fixed fuel factor. In 2010, the Company received approval to implement a formula to determine its fuel factor which adjusts natural gas and purchased power to reflect natural gas futures prices. The Company can 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 fuel costs 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 fuel cost recovery 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.
During 2012, the Company filed the following petition with the PUCT to refund recent fuel cost over-recoveries, due primarily to fluctuations in natural gas markets and consumption levels. The table summarizes the docket number assigned by the PUCT, the date the Company filed the petition and the date a final order was issued by the PUCT approving the refund to customers. The fuel cost over-recovery period represents the months in which the over-recoveries took place, and the refund period represents the billing month in which customers received the refund amounts shown, including interest:
The Company filed the following petition in 2012 with the PUCT to revise its fixed fuel factor pursuant to the fuel factor formula authorized in PUCT Docket No. 37690:
Generation CCN Filing. On May 2, 2012, the Company filed a petition with the PUCT requesting a CCN to construct a new generating facility to be located at a new plant site, the Montana Power Station, in east El Paso. The new facility will initially consist of two 88 MW simple-cycle aeroderivative combustion turbines, which will be powered by natural gas. The first unit is scheduled to become operational in 2014. On December 13, 2012, the PUCT issued a Final Order approving the requested CCN.
The Company has also filed two air permit applications for the Montana Power Station. One application was filed with the Texas Commission on Environmental Quality ("TCEQ") and a contested hearing on the merits of the application is scheduled for May 1, 2013, before the State Office of Administrative Hearings in Austin, Texas. Several parties, representing affected individuals as defined by TCEQ, have requested status in the hearing. The second air permit application is an EPA greenhouse permit application which remains under review. A final permit is expected from the EPA by August 2013 if there is no appeal. While the Company believes that the Montana Power Station complies with all air regulations, it cannot predict the final outcome of these applications.
Energy Efficiency Cost Recovery Factor ("EECRF"). On April 30, 2012, the Company filed an application to revise its EECRF and to establish revised energy efficiency goals and cost caps, pursuant to the Public Utility Regulatory Act ("PURA") Section 39.905. On September 20, 2012, the PUCT approved a unanimous settlement resolving all issues. The settlement allows the Company to recover $5.5 million in energy efficiency costs, revised the Company’s demand and energy goals and granted the Company’s request to increase its 2013 EECRF effective with billings in January 2013.
Military Base Discount Recovery Factor ("MBDRF"). On July 16, 2012, the Company filed a petition to revise its MBDRF. On November 16, 2012, the PUCT approved a unanimous stipulation and settlement, with the City of El Paso and Staff, which provides for the surcharge to be increased from 0.936% to 1.055% of customer bills. The revised MBDRF is designed to recover estimated discounts and the recovery of past under-recoveries spread over two years, totaling $4.6 million and is effective with December 2012 billings.
Other Required Approvals. The Company has obtained all other required approvals for recovery of fuel costs through fixed fuel factors, other tariffs and approvals as required by the PURA and the PUCT.
New Mexico Regulatory Matters
2009 New Mexico Stipulation. On December 10, 2009, the NMPRC issued a final order conditionally approving the stipulated rates in NMPRC Case No. 09-00171-UT. The stipulated rates went into effect with January 2010 bills.
Generation CCN Filing. On May 2, 2012, the Company filed a petition with the NMPRC requesting a CCN to construct a new generation facility to be located at a new plant site, the Montana Power Station, in east El Paso. The NMPRC approved the CCN on January 23, 2013.
2012 Annual Procurement Plan Pursuant to the Renewable Energy Act. On June 29, 2012, the Company filed its application for approval of its 2012 Annual Procurement Plan pursuant to the New Mexico Renewable Energy Act. On December 11, 2012, the NMPRC issued a final order approving the renewable procurement plan with modifications recommended by the Hearing Examiner. The plan sets out the Company's procurement of renewable resources and estimated costs for 2013 and 2014 to meet Renewable Portfolio Standards ("RPS") and resource diversity requirements. The approved plan provides for the RPS and diversity requirements for 2013 and 2014 to be met with a combination of previously approved resources and excused the Company from a requirement to make-up a deficiency in the "other" diversity requirement for 2011 and from meeting the "other" diversity requirement for the 2013 and 2014 compliance years. Costs for purchases of renewable energy delivered to the Company are recovered through the New Mexico Fuel and Purchased Power Cost Adjustment Clause ("FPPCAC") and purchases of renewable energy credits are recovered through base rates.
Long-Term Purchased Power Agreement with Macho Springs. On November 21, 2012, the Company filed an application with the NMPRC requesting approval of a Long-Term Purchase Power Agreement ("LTPPA") with Macho Springs Solar, LLC
("Macho Springs") to purchase energy from a 50 MW solar facility to be constructed by Macho Springs in the Company's New Mexico service territory. The Company also seeks approval of the recovery of costs associated with the LTPPA through the Company's FPPCAC. The hearing is scheduled to begin March 14, 2013 and a final order is expected by the end of May 2013.
Other Required Approvals. The Company has obtained all other required approvals for other tariffs, securities transactions, long-term resource plans, recovery of energy efficiency costs through a base rate rider and other approvals as required by the NMPRC.
Federal Regulatory Matters
Public Service Company of New Mexico's (“PNM”) 2010 Transmission Rate Case. On October 27, 2010, PNM filed a Notice of Transmission Rate Changes for transmission delivery services provided by PNM. These rates went into effect on June 1, 2011. The Company takes transmission service from PNM. On January 2, 2013, the FERC issued a letter order approving a unanimous stipulation and agreement. Pursuant to the stipulation, on January 31, 2013, PNM refunded $1.9 million, for amounts that PNM collected since June 1, 2011, in excess of settlement rates. This amount was recorded in the fourth quarter of 2012 as a reduction of transmission expense.
Other Required Approvals. The Company has obtained all required approvals for rates and tariffs, securities transactions and other approvals as required by the FERC.
Department of Energy ("DOE"). 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 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 E for discussion of spent fuel storage and disposal costs.
Sales for Resale
The Company provides firm capacity and associated energy to the RGEC pursuant to an ongoing contract with a two-year notice to terminate provision. The Company also provides network integrated transmission service to RGEC pursuant to the Company's Open Access Transmission Tariff ("OATT"). The contract includes a formula-based rate that is 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.
Power Sales Contracts
The Company has entered into several short-term (three months or less) off-system sales contracts throughout 2013.
Franchises and Significant Customers
El Paso and Las Cruces Franchises
The Company has a franchise agreement with El Paso, the largest city it serves. The franchise agreement allows the Company to utilize public rights-of-way necessary to serve its retail customers within El Paso. The Company is also providing electric distribution service to Las Cruces under an implied franchise by satisfying all obligations under the franchise agreement that expired April 30, 2009.
The franchise arrangements held between the Company and the cities of El Paso and Las Cruces are detailed below:
(a) Based on a percentage of revenue.
(b) The additional fee of 0.75% is to be placed in a restricted fund to be used solely for economic development and renewable energy purposes.
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 installations represent approximately 5% of annual retail revenues. The Company signed a contract with Fort Bliss in October 2008 under which Fort Bliss takes retail electric service from the Company. The contract with Fort Bliss expired in 2010 and the Company is serving Fort Bliss under the applicable Texas tariffs. 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.
Executive Officers of the Registrant
The executive officers of the Company are elected annually and serve at the discretion of the Board of Directors. The executive officers of the Company as of February 25, 2013, were as follows:
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 settlement approved in the Company's 2012 Texas rate case, PUCT Docket No. 40094, established the Company's current retail base rates in Texas, effective May 1, 2012. In addition, the settlement in the Company's 2009 New Mexico rate case, NMPRC Case No. 09-00171-UT, established rates in New Mexico that became effective January 2010.
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 a 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 and recovery of expenses may lag behind the occurrence of those expenses. 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 future Texas rate cases or New Mexico rate cases will result in base rates that will allow us to fully recover our costs including a reasonable return on invested capital. There can be no assurance that regulators will determine that all of our costs are reasonable and have been prudently incurred including cost associated with future plant retirement and asset retirement obligations. It is also likely that third parties will intervene in any 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
The construction of our next generating plant addition, Rio Grande Unit 9, will add an aeroderivative unit with a generating capacity of 87 MW. It should reach commercial operation by May 2013. In addition, we have received approval from both the PUCT and NMPRC of the CCN to construct the first two units of the Montana Power Station, a new plant site, which will initially consist of two 88 MW simple-cycle aeroderivative combustion turbines. We have risk related to recovering all costs associated with the completion of the construction of Rio Grande Unit 9 and other new units.
In 2012, we issued $150 million in aggregate principal amount of 3.30% Senior Notes, due December 15, 2022. The 3.30% Senior Notes along with our revolving credit facility could help fund the construction of the Montana Power Station and other new units. The costs of financing and constructing these units 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 these units are 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 these new units or other new units.
Continuing Weakness in the Economy and Uncertainty in the Financial Markets Could Reduce Our Sales, Hinder Our Capital Programs and Increase Our Funding Obligations for Pensions and Decommissioning
In recent years, the global credit and equity markets and the overall economy have been through a state of turmoil. These and future 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 performance may reduce the value of our financial assets and decommissioning trust investments. Such market results 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, continued economic volatility may result in reduced customer demand, both in the retail and wholesale markets, and increases in customer delinquencies and write-offs. 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 36% of our available net generating capacity and provided approximately 46% of our energy requirements for the twelve months ended December 31, 2012. Palo Verde comprises approximately 32% 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 92.3% and 90.7% in the twelve months ended December 31, 2012 and 2011, respectively.
Our ability to increase retail base rates in Texas and New Mexico is limited. 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, 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 reasonable and necessary 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 a previous purchased
power contract. Fuel and purchased power expenses in New Mexico and Texas are subject to reconciliation by the PUCT and 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. Our most recent rate filing at the PUCT (Docket No. 40094) included a request to reconcile $356.6 million of fuel expense for the period July 1, 2009 through September 30, 2011. However, as part of the settlement in the case, we agreed to withdraw our fuel reconciliation request. We agreed to file a fuel reconciliation request covering the period beginning July 1, 2009 and ending no later than June 30, 2013 by December 31, 2013 or as part of our next rate case, if earlier. In the event that recovery of fuel and purchased power expenses is denied in 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. In Texas, we can seek to revise our fixed fuel factor based upon our approved formula at least four months after our last revision except in the month of December. 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, the Company realizes a lag in the ability to reflect increases in fuel costs in its fuel recovery mechanisms in Texas. As a result, cash flow is impacted due to the lag in payment of fuel costs and collection of fuel costs from customers. 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. At December 31, 2012 and 2011, the Company had a net over-collection balance of $4.6 million and a net under-collection balance of $7.0 million, respectively.
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 and severe weather conditions. The advanced age of several of our gas-fired generating units in or near El Paso increases the vulnerability of these units. 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 additional purchased power cost would be subject to review and approval of the PUCT and the NMPRC in reconciliation proceedings. As noted above, in the event that recovery for fuel and purchased power expenses could differ from the amounts we are allowed to collect from our customers, we would incur a loss to the extent of the disallowance. 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 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 flow 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 access to, 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 was codified in the Public Utility Regulatory Act ("PURA") in June 2011. PURA identifies 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 a regional transmission organization 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 flow and financial condition.
Future Costs of Compliance with Environmental Laws and Regulations Could
Adversely Affect Our Operations and Consolidated Financial Results
We are or may become subject to extensive federal, state and local environmental statutes, rules and regulations relating to discharges into the air, air quality, discharges of effluents into water, water quality, the use of water, the handling, disposal and clean-up of hazardous and non-hazardous substances and wastes, natural resources, and health and safety. Compliance with these legal requirements, which change frequently and often become more restrictive, could require us to commit significant capital and operating resources toward permitting, emission fees, environmental monitoring, installation and operation of air quality control equipment and purchases of air emission allowances and/or offsets. These could also result in limitations in operating hours and/or changes in construction schedules for future generating units.
Costs of compliance with environmental laws and regulations or fines or penalties resulting from non-compliance, if not recovered in our rates, could adversely affect our operations and/or consolidated financial results, especially if emission and/or discharge limits are tightened, more extensive permitting requirements are imposed, additional substances become regulated and the number and types of assets we operate increases. We cannot estimate our compliance costs or any possible fines or penalties with certainty, or the degree to which such costs might be recovered in our rates, due to our inability to predict the requirements and timing of implementation of environmental rules or regulations. For example, the EPA has issued in the recent past various final and proposed regulations regarding air emissions from our operations as well as the rest of the utility sector, including the CSAPR and the GHG New Source Performance Standard ("NSPS") for Electric Generating Units. If these regulations become finalized and survive legal and Congressional challenges, the cost to us to comply could adversely affect our operations and consolidated financial results.
Cost of compliance with environmental laws and regulations also adds uncertainty to the timing and costs of our future generation additions. We have filed two air permit applications for the Montana Power Station, our proposed new generation facility in far east El Paso, with the TCEQ and the EPA. A contested hearing on the merits of the application filed with the TCEQ is scheduled for May 1, 2013, before the State Office of Administrative Hearings in Austin, Texas. Several parties, representing affected individuals as defined by TCEQ, have requested status in the hearing. The application filed with the EPA remains under review. While we believe that the Montana Power Station complies with all air regulations, we cannot predict the final outcome of these applications.
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 Company emits GHGs through the operation of its power plants. Federal legislation had been introduced in both houses of Congress to regulate the emission of GHGs and numerous states have adopted programs to stabilize or reduce GHG emissions. Additionally, the EPA is proceeding with regulation of GHG under the CAA. Under EPA regulations finalized in May 2010, the EPA began regulating GHG emissions from certain stationary sources, such as power plants, in January 2011. On March 27, 2012, EPA released its proposed NSPS for new and modified electric generating units. The potential impact of these rules on the Company is unknown at this time, but they could result in significant costs, limitations on operating hours, and/or changes in construction schedules for future generating units.
It is not currently possible to predict how any pending, proposed or future GHG 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 legislation or regulation of GHG 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 GHG, and could have a material adverse effect on our business, financial condition, reputation or results of operations.
Security Breaches, Criminal Activity, Terrorist Attacks and Other Disruptions to Our Information Technology Infrastructure Could Interfere With Our Operations, Could Expose Us or Our Customers or Employees to a Risk of Loss, and Could Expose Us to Liability, Regulatory Penalties, Reputational Damage and Other Harm to Our Business
We rely upon our information technology infrastructure to manage or support a variety of business processes and activities, including the generation, transmission and distribution of electricity, supply chain functions, and the invoicing and collection of payments from our customers. We also use information technology systems for internal accounting purposes and to comply with financial reporting, legal and tax requirements. Our information technology networks and infrastructure may be vulnerable to damage, disruptions or shutdowns due to attacks by hackers, breaches due to employee error or malfeasance, maintenance downtimes, system failures, natural disasters or other catastrophic events. The occurrence of any of these events could impact the reliability of our generation, transmission and distribution systems and energy marketing and trading functions; could expose us
or our customers or employees to a risk of loss or misuse of information; and could result in legal claims or proceedings, liability or regulatory penalties against us, damage our reputation or otherwise harm our business.
Additionally, we cannot predict the impact that any future information technology or terrorist attack may have on the energy industry in general. The effects of such attacks against us or others in the energy industry could increase the cost of regulatory compliance, increase the cost of insurance coverage or result in a decline in the U.S. economy which could negatively affect our results of operations and financial condition. Ongoing and future governmental efforts to regulate cybersecurity in the energy industry, including the Improving Critical Infrastructure Cybersecurity executive order and the proposed Cyber Intelligence Sharing and Protection Act, could lead to increased regulatory compliance costs, require us to make capital expenditures or otherwise harm our business.
Item 1B.
Item 1B.
Unresolved Staff Comments
None.
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.
The Company owns an executive and administrative office building in El Paso. The Company leases 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. The Company also leases certain warehouse facilities in El Paso under a lease which expires in December 2014. The Company 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 “Environmental Matters” and “Regulation” for discussion of the effects of government legislation and regulation on the Company.
Item 4.
Item 4.
Mine Safety Disclosures
Not Applicable.
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, and quarterly dividends per share paid by the Company 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 Edison Electric Institute’s Index of investor-owned electric utilities and the NYSE Composite, setting the value of each at December 31, 2007 to a base of 100. The table sets forth the relative yearly percentage change in the Company’s cumulative total shareholder return, assuming reinvestment of dividends, as compared to EEI and the NYSE, as reflected in the graph.
As of January 31, 2013, there were 2,760 holders of record of the Company’s common stock. The Company has been paying quarterly cash dividends on its common stock since June 30, 2011 and paid a total of $38.9 million in cash dividends during the twelve months ended December 31, 2012. On January 17, 2013, our Board of Directors declared a quarterly cash dividend of $0.25 per share payable on March 29, 2013 to shareholders of record on March 14, 2013. The Board of Directors plans to review the Company's dividend policy annually in the second quarter of each year. We are currently targeting a payout ratio of approximately 45%. Since 1999, the Company has also returned cash to stockholders through a stock repurchase program pursuant to which the Company has bought approximately 25.4 million shares at an aggregate cost of $423.6 million, including commissions. Under the Company’s program, purchases can be made at open market prices or in private transactions and repurchased shares are available for issuance under employee benefit and stock incentive plans, or may be retired. On March 21, 2011, the Board of Directors authorized a repurchase of up to 2.5 million shares of the Company’s outstanding common stock (the “2011 Plan”). No shares of common stock were repurchased during the twelve months ended December 31, 2012 under the 2011 Plan. As of December 31, 2012, 393,816 shares remain eligible for repurchase under the 2011 Plan.
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 and per share data):
______________________
(a)
Extraordinary gain for 2010 represents a $10.3 million extraordinary gain or $0.24 earnings per share related to Texas regulatory assets.
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 Generally Accepted Accounting Principles ("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, 2012, we had recorded regulatory assets currently subject to recovery in future rates of approximately $101.6 million and regulatory liabilities of approximately $22.2 million as discussed in greater detail in Note D 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 or to the individual regulatory assets recorded, 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. 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. If the rates of return earned by the trusts fail to meet expectations or if 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, 2012, 2011 and 2010. Income before extraordinary item for the years ended December 31, 2012, 2011 and 2010 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 2012 and 2011, 2011 and 2010, and 2010 and 2009 (in thousands):
______________________
(a)
Retail non-fuel base revenues decreased in 2012 compared to 2011 primarily due to a decrease in non-fuel base revenues from sales to small commercial and industrial customers and large commercial and industrial customer due to a reduction in non-fuel base rates in Texas effective May 1, 2012, increased use of lower interruptible rates and decreased consumption by several 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 2011 compared to 2010 primarily due to a 3.1% increase in kWh sales to retail customers reflecting hotter summer weather with higher non-fuel base summer rates and 1.4% growth in the average number of retail customers served in 2011.
(c)
Retail non-fuel base revenues increased in 2010 compared to 2009 primarily due to new non-fuel base rates in New Mexico and Texas to recover capital investments to meet customer growth and a 4.4% increase in retail kWh sales.
(d)
Administrative and general expenses increased primarily due to increased pension and benefits expense as a result of changes in actuarial assumptions used to calculate expenses for our retiree benefit plans.
(e)
Deregulated Palo Verde Unit 3 revenues in 2012 reflect lower proxy market prices associated with the decline in natural gas prices and lower sales of the deregulated portion of Palo Verde Unit 3 to retail customers due mostly to its planned refueling outage in March and April 2012, and an increase in the costs of nuclear fuel burned.
(f)
Transmission revenues increased in 2011 primarily due to a settlement agreement with Tucson Electric Power Company resolving a transmission dispute that resulted in a one-time adjustment to income of $3.9 million, pre-tax and annual revenue of $1.1 million per year.
(g)
Operations and maintenance at gas-fired fuel generating stations increased in 2011 largely as a result of weather-related damage during severe winter weather in February 2011 and freeze protection upgrades.
(h)
Taxes other than income taxes increased in 2010 compared to 2009 due to revenue-related taxes and increased property taxes.
(i)
Customer care expense decreased in 2012 compared to 2011 primarily due to a decrease in the provision for uncollectible accounts reflecting improved collection efforts.
(j)
Customer care expense increased in 2011 compared to 2010 primarily due to increased costs for customer-related activities, an increase in uncollectible customer accounts, and an increase in payroll costs.
(k)
Customer care expense increased in 2010 compared to 2009 primarily due to the transition to our new customer billing system and increased uncollectible customer accounts.
(l)
Depreciation and amortization expense decreased in 2012 compared to 2011 due to a reduction in depreciation rates for Palo Verde reflecting the approval of a license extension for Palo Verde by the NRC in April 2011, and reduced depreciation
rates on gas-fired generating units and on transmission and distribution plant as a result of the Texas rate case settlement in 2012. The depreciation rate reductions were partially offset by higher depreciation expense due to an increase in depreciable plant.
(m)
Depreciation and amortization expense increased in 2010 compared to 2009 due to increased depreciable plant balances and increased depreciation rates.
(n)
AFUDC (allowance for funds used during construction) increased primarily due to higher balances of construction work in progress subject to AFUDC primarily reflecting construction work in progress on Rio Grande Unit 9 and the Montana Power Station in 2012.
(o)
AFUDC decreased in 2011 compared to 2010 primarily due to lower balances of construction work in progress subject to AFUDC reflecting the completion and placing in service the Newman Unit 5 Phase II generating plant addition in April 2011.
(p)
Off-system sales margins decreased in 2011 compared to 2010 primarily due to lower average market prices for power and an increase in sharing of off-system sales margins with customers from 25% to 90% effective in July 2010.
(q)
Off-system sales margins decreased in 2010 compared to 2009 due to increased sharing of off-system sales margins with customers from 25% to 90% effective July 1, 2010 consistent with prior rate agreements in Texas and New Mexico.
(r)
Palo Verde non-fuel operations and maintenance expense decreased in 2010 compared to 2009 primarily due to decreased maintenance costs at Units 2 and 3 as the result of reduced costs for scheduled refueling outages.
(s)
Transmission and distribution operations and maintenance expense increased in 2011 compared to 2010 primarily due to increased wheeling expense, a reliability study for the North American Electric Reliability Corporation, and an increase in payroll costs.
(t)
A one-time charge to income tax expense was incurred in 2010 to recognize a change in tax law enacted in the Patient Protection and Affordable Care Act to eliminate the tax benefit related to the Medicare Part D subsidies with no comparable tax expense in 2011.
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.
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 4% of our non-fuel base revenues during such periods. As shown in the table above, residential and small commercial customers comprise 75% or more of our non-fuel base revenues. While this customer base is more stable, it is also more sensitive to changes in weather conditions. The current rate structure in New Mexico and Texas reflects higher base rates during the peak summer season of May through October and lower base rates during November through April for our residential and small commercial and industrial customers. 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:
Weather significantly impacts our residential, small commercial and industrial customers, and to a lesser extent, our sales to public authorities. 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 2012, 2011 and 2010.
Customer growth is a key driver in the growth of retail sales. The average number of retail customers grew 1.3% in 2012 and 1.4% in 2011. See the tables presented on pages 30 and 31 which provide detail on the average number of retail customers and the related revenues and kWh sales.
Retail non-fuel base revenues. The rate structure effective July 1, 2010 through April 30, 2012 in Texas was based on the final order in PUCT Docket No. 37690 which approved a settlement that called for an annual increase of $17.15 million in non-fuel base rates. On April 17, 2012, the City council (the “Council”) of El Paso, Texas approved the settlement of our 2012 Texas retail rate case and fuel reconciliation in PUCT Docket No. 40094 and on April 26, 2012, the administrative law judge issued an order implementing the settlement rates as temporary rates effective May 1, 2012. The PUCT approved the settlement on May 18, 2012. Under the terms of the settlement, among other things, we agreed to a reduction in our current non-fuel base rates of $15 million annually, with the decrease being allocated primarily to Texas retail commercial and industrial customer classes.
Retail non-fuel base revenues decreased by $9.7 million or 1.7% for the twelve months ended December 31, 2012 when compared to the same period in 2011. Non-fuel base revenues from sales to small commercial and industrial customers and large commercial and industrial customers decreased 4.1% and 7.4%, respectively, reflecting the reduction in our non-fuel base rates as stipulated in PUCT Docket No. 40094. In addition, increased use of lower interruptible rates and decreased consumption by several large commercial and industrial customers contributed to the decrease in non-fuel base revenues. KWh sale to large commercial and industrial customer decreased 1.2%. KWh sales to small commercial and industrial customers increased 0.6% primarily due to the 0.8% increase in the average number of customers served. KWh sales to residential customers increased 0.6% due to the 1.4% increase in the average number of customers served despite significantly milder weather in 2012 compared to 2011. KWh sales to public authorities increased 2.4% and non-fuel base revenues from public authorities increased 1.9%.
Retail non-fuel base revenues increased by $33.6 million, or 6.3% for the twelve months ended December 31, 2011 when compared to the same period in 2010. The increase was primarily due to a 3.1% increase in kWh sales to retail customers, reflecting hotter summer weather with higher non-fuel base summer rates, and 1.4% growth in the average number of retail customers served. During the twelve months ended December 31, 2011, cooling degree days were 14% above the same period in 2010 and 20% above the 10-year average. KWh sales to residential customers and small commercial and industrial customers increased 5.0% and 2.5%, respectively, during the twelve months ended December 31, 2011 compared to the same period in 2010. Sales to other public authorities increased due to increased sales to military bases at higher non-fuel base rates.
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. In Texas, fuel costs are recovered through a fixed fuel factor. We can seek to revise our fixed fuel factor based upon our approved formula at least four months after our last revision except in the month of December. 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. Fuel over and under recoveries are considered material when they exceed 4% of the previous twelve months' fuel costs.
We over-recovered fuel costs by $18.5 million in the twelve months ended December 31, 2012. In the twelve months ended December 31, 2011 we under-recovered fuel costs by $13.9 million and in the twelve months ended December 31, 2010, we over-recovered fuel costs by $35.4 million. Refunds of $6.9 million, $12.0 million and $34.8 million were returned to our Texas customers in the twelve months ended December 31, 2012, 2011 and 2010, respectively. At December 31, 2012, we had a net fuel over-recovery balance of $4.6 million, including $2.3 million in Texas and $2.3 million in New Mexico. Over-recoveries in New Mexico will be refunded through our fuel adjustment clause during 2013.
Off-system sales. 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. We share 90% of off-system sales margins with our Texas and New Mexico customers, and we retain 10% of off-system sales margins. Prior to July 1, 2010, we shared 25% of off-system sales margins with customers and retained 75% of off-system sales margins through June 30, 2010 pursuant to rate agreements in prior years. We are 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.
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, 2012, 2011 and 2010 (in thousands except for MWhs).
Off-system sales revenues decreased $5.3 million or 6.8% for the twelve months ended December 31, 2012 when compared to 2011 as a result of lower average market prices for power and a 2.7% decline in MWh sales. For the twelve months ended December 31, 2012, retained margins increased $1.7 million when compared to the same period in 2011 primarily due to the negative impacts in 2011 of power purchases required for system reliability when key generation and transmission facilities were either out of service or were threatened to be out of service. Off-system sales revenues decreased $27.3 million, or 25.9% for the twelve months ended December 31, 2011 when compared to 2010 as a result of lower average market prices for power and a 4.8% decline in MWh sales. For the twelve months ended December 31, 2011, retained margins decreased $6.2 million when compared to the same period in 2010. Off-system margins were negatively affected by lower costs of natural gas which impact the average market prices in the wholesale power markets. Off-system sales margins were also negatively impacted in 2011 by power purchases required for system reliability.
Comparisons of kWh sales and operating revenues are shown below (in thousands):
___________________________
(1)
Excludes $6.9 million and $12.0 million of refunds in 2012 and 2011, respectively, related to prior periods' Texas deferred fuel revenues.
(2)
Includes deregulated Palo Verde Unit 3 revenues for the New Mexico jurisdiction of $9.8 million and $14.8 million in 2012 and 2011, respectively.
(3)
Represents revenues with no related kWh sales. 2011 includes a one-time $3.9 million settlement of a transmission dispute with Tucson Electric Power Company.
_______________________
(1)
Excludes $12.0 million and $34.8 million of refunds in 2011 and 2010, respectively, related to prior periods' Texas deferred fuel revenues.
(2)
Includes deregulated Palo Verde Unit 3 revenues for the New Mexico jurisdiction of $14.8 million and $16.1 million in 2011 and 2010, respectively.
(3)
Represents revenues with no related kWh sales. 2011 includes a one-time $3.9 million settlement of a transmission dispute with Tucson Electric Power Company.
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 36% of our available net generating capacity and approximately 54% of our Company-generated energy for the twelve months ended December 31, 2012. 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.
Energy expenses decreased $47.3 million or 15.9% for the twelve months ended December 31, 2012 compared to 2011, primarily due to (i) a decrease of $36.4 million in natural gas costs due to a 28% decrease in the average costs of gas partially offset by a 6% increase in MWh generated with natural gas, and (ii) decreased costs of purchased power of $14.9 million resulting from a 17% decrease in MWh purchased and a 3% decrease in the average price of power purchased. This decrease was partially offset by an increase of $5.7 million in the cost of nuclear fuel due to an 11% increase in the cost of nuclear fuel consumed and a 2% increase in MWh generated with nuclear fuel.
Average costs per MWh were essentially flat while energy expenses increased $6.9 million or 2.4% for the twelve months ended December 31, 2011 as compared to twelve months ended December 31, 2010 due to increased energy requirements. Energy expenses in 2011, compared to 2010, increased primarily due to: (i) an increase of $10.7 million in natural gas costs due to a 16% increase in MWh generated with natural gas partially offset by a 6% decrease in the average price of natural gas; (ii) an increase of $8.7 million in the cost of nuclear fuel primarily due to a 14% increase in the cost of nuclear fuel consumed and a $3.3 million DOE settlement related to spent nuclear fuel received in 2010 with no comparable activity in 2011; and (iii) an increase of $4.3 million in coal expense due to a $2.3 million adjustment for the amortization of final coal reclamation costs in accordance with the final order in PUCT Docket No. 38361, a favorable adjustment related to a contract renegotiation of $0.5 million in 2010, and a 12% increase in the cost of coal burned. These increases were partially offset by a $16.8 million decrease in purchased power cost due to a 12% decrease in MWhs purchased and a 7% decrease in the average price of purchased power.
The table below details the sources and costs of energy for 2012, 2011 and 2010.
_____________________
(a)
Natural gas costs exclude $3.2 million of energy expenses capitalized related to Newman Unit 5 pre-commercial testing recorded in 2011.
(b)
Coal costs include $2.3 million adjustment for final coal reclamation amortization in accordance with PUCT Docket No. 38361 recorded in 2011.
(c)
Includes a DOE refund of $3.3 million recorded in 2010.
Other operations expense
Other operations expense increased $7.0 million or 3.0% in 2012 compared to 2011 primarily due to: (i) increased pension and benefits expense of $5.5 million reflecting changes in actuarial assumptions used to calculate expenses for our pension plans; (ii) increased power production operation expense at both Palo Verde and our fossil-fuel generating plants; and (iii) increased distribution operations expense. These increases were partially offset by decreased customer care expenses related to a decrease in our provision for uncollectible customer accounts reflecting improved collection efforts.
Other operations expense increased $5.3 million or 2.4% in 2011 compared to 2010 primarily due to: (i) increased customer care expenses of $3.3 million related to increased costs for customer-related activities, an increase in uncollectible customer accounts, and an increase in payroll costs; and (ii) increased transmission operations expense of $2.5 million primarily due to increased wheeling expense and a reliability study for the North American Electric Reliability Corporation.
Maintenance expense
Maintenance expenses decreased $1.8 million or 2.8% in 2012 compared to 2011 due primarily to decreased maintenance expense at Palo Verde of $3.2 million as a result of decreased maintenance during refueling outages in 2012 compared to refueling outages in 2011 partially offset by increased maintenance expense at our fossil-fuel generating plants.
Maintenance expenses increased $5.3 million or 9.3% in 2011 compared to 2010 due to an increase in maintenance expense largely as a result of weather-related damage during severe winter weather in February 2011 and freeze protection upgrades at our fossil-fuel generating plants.
Depreciation and amortization expense
Depreciation and amortization expense decreased $2.8 million or 3.4% in 2012 compared to 2011 due to a reduction in depreciation rates for Palo Verde reflecting the approval of a license extension for Palo Verde by the NRC in April 2011, and reduced depreciation rates on gas-fired generating units and on transmission and distribution plant as a result of the Texas rate case settlement in 2012. The depreciation rate reductions were partially offset by higher depreciation expense due to an increase in depreciable plant.
Depreciation and amortization expense increased $0.3 million or 0.4% in 2011 compared to 2010 primarily due to increases in depreciable plant balances including Phase II of Newman Unit 5 and increased depreciation rates, largely offset by a reduction in depreciation rates related to Palo Verde resulting from the approval of the license extension for Palo Verde by the NRC in April 2011.
Taxes other than income taxes
Taxes other than income taxes increased $1.9 million or 3.4% in 2012 compared to 2011 primarily due to increased revenue-related taxes and increased property taxes in New Mexico. Taxes other than income taxes increased $1.1 million or 2.0% in 2011 compared to 2010 primarily due to increased revenue-related taxes and increased property taxes in Texas.
Other income (deductions)
Other income (deductions) increased $2.6 million or 22.4% in 2012 compared to 2011 primarily as a result of: (i) increased allowance for equity funds used during construction (“AEFUDC”) of $1.3 million due to higher balances of construction work in progress in 2012, and (ii) a $1.1 million gain recognized on the sale of assets with no comparable amount in 2011.
Other income (deductions) decreased $2.8 million or 19.4% in 2011 compared to 2010 due to decreased AEFUDC due to lower balances of construction work in progress in 2011. Also during 2011, we incurred net unrealized and realized losses on equity investments in our decommissioning trust of $1.4 million compared to $0.1 million in 2010. The losses on equity investments were offset by increased interest income.
Interest charges (credits)
Interest charges (credits) decreased $0.1 million or 0.3% in 2012 compared to 2011 primarily due to increased allowance for borrowed funds used during construction (“ABFUDC”) as a result of higher balances of construction work in progress in 2012 partially offset by interest expense on the $150 million in aggregate principal amount of 3.30% Senior Notes issued in December 2012.
Interest charges (credits) increased $3.2 million or 7.5% in 2011 compared to 2010 primarily due to: (i) decreased ABFUDC as a result of lower balances of construction work in progress in 2011; and (ii) increased commitment fees on our revolving credit facility.
Income tax expense
Income tax expense, before extraordinary item, decreased by $6.7 million or 12.5% in 2012 compared to 2011 primarily due to a decrease in pre-tax income. Income tax expense, before extraordinary item, increased by $2.7 million or 5.3% in 2011 compared to 2010 primarily due to increased pre-tax income partially offset by the recognition of a one-time non-cash charge to tax expense related to the impact of the tax deduction for the Medicare Part D subsidies from the Patient Protection and Affordable Care Act (“PPACA”) in March 2010 with no comparable amount in 2011. In the first quarter of 2010 the Company was required to recognize the impacts of the tax law change at the time of enactment and recorded a one-time non-cash charge to income tax expense of approximately $4.8 million. A provision of the PPACA is that, beginning in 2013, the income tax deductions for the cost of providing certain prescription drug coverage will be reduced by the amount of the Medicare Part D subsidies received.
Extraordinary Item
As a regulated electric utility, we prepare our financial statements in accordance with the FASB guidance for regulated operations. FASB guidance for regulated operations requires us to show certain items as assets or liabilities on our balance sheet when the regulator provides assurance that these items will be charged to and collected from our customers or refunded to our customers. In the final order for PUCT Docket No. 37690, we were allowed to include the previously expensed loss on reacquired debt associated with the refinancing of first mortgage bonds in 2005 in our calculation of the weighted cost of debt to be recovered from our customers. We recorded the impacts of the re-application of FASB guidance for regulated operations to our Texas jurisdiction in 2006 as an extraordinary item. In order to establish this regulatory asset, we recorded an extraordinary gain of $10.3 million, net of income tax expense of $5.8 million, in our 2010 statements of operations. This item was recorded as a regulatory asset during the quarter ended September 30, 2010 pursuant to the final order received from the PUCT and will be amortized over the remaining life of our 6% Senior Notes due in 2035.
New accounting standards
In February 2013, the FASB issued new guidance (ASU 2013-02, Comprehensive Income (Topic 220)) to improve the reporting of reclassifications out of accumulated other comprehensive income (loss). ASU 2013-02 requires an entity to report the effect of significant reclassifications out of accumulated other comprehensive income (loss) on the respective line items in net income if the amount being reclassified is required under FASB guidance to be reclassified in its entirety to net income in the same reporting period. For other amounts that are not required under FASB guidance to be reclassified in their entirety to net income in the same reporting period, an entity is required to cross-reference other disclosures required under FASB guidance that provide additional detail about those amounts.
Substantially all of the information that ASU 2013-02 requires is already required to be disclosed elsewhere in the financial statements under FASB guidance. However, the new requirement about presenting information about amounts reclassified out of accumulated other comprehensive income (loss) and their corresponding effect on net income will present, in one place, information about significant amounts reclassified and, in some cases, cross-references to related footnote dislcosures. Currently, this information is presented in different places thoughout the financial statements. We will be required to present the corresponding effects of components reclassified out of accumulated other comprehensive income (loss) on net income with cross-references to other disclosures because FASB guidance does not require that all of our components be reclassified from accumulated other comprehensive income (loss) to net income in their entirety in the same reporting period.
ASU 2013-02 is effective prospectively for reporting periods beginning after December 15, 2012 and early adoption is permitted. We will implement ASU 2013-02 in the first quarter of 2013.
Inflation
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
In December 2012, we issued $150 million of 3.30% Senior Notes due to mature on December 15, 2022 to fund construction expenditures and to repay the outstanding balance of our revolving credit facility used for working capital and general corporate purposes. We continue to maintain a strong balance of common stock equity in our capital structure which supports our bond ratings, allowing us to obtain financing from the capital markets at a reasonable cost. At December 31, 2012, our capital structure, including common stock, long-term debt, and short-term borrowings under the revolving credit facility, consisted of 44.7% common stock equity and 55.3% debt. At December 31, 2012, we had on hand $111.1 million in cash and cash equivalents.
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, operating expenses including fuel costs, maintenance costs, dividends, and taxes.
Capital Requirements. During the twelve months ended December 31, 2012, our capital requirements primarily consisted of expenditures for the construction and purchase of electric utility plant, purchases of nuclear fuel, and the payment of common stock dividends. Projected utility construction expenditures are to expand and update our transmission and distribution systems, add new generation, and make capital improvements and replacements at Palo Verde and other generating facilities. We are constructing Rio Grande Unit 9, an aeroderivative gas turbine unit with a net dependable generating capacity of 87 MW that should reach commercial operation in May 2013, at an estimated cost of approximately $92.7 million, including AFUDC. As of December 31, 2012, we had expended $81.4 million on Rio Grande Unit 9, including AFUDC, of which $44.2 million was incurred during 2012. Estimated construction expenditures for all capital projects for 2013 are approximately $264 million, and we expect our current cash balances, cash from operations, and short-term borrowings from our revolving credit facility to continue to be the primary source of funds for these capital expenditures. See Part I, Item 1, “Business - Construction Program”. Cash capital expenditures for new electric plant were $202.4 million in the twelve months ended December 31, 2012 and $178.0 million in the twelve months ended December 31, 2011.
On December 28, 2012, we paid $10.0 million of quarterly dividends to shareholders. We paid a total of $38.9 million in cash dividends during the twelve months ended December 31, 2012. On January 17, 2013, our Board of Directors declared a quarterly cash dividend of $0.25 per share payable on March 29, 2013 to shareholders of record on March 14, 2013 which will require cash of $10.0 million. We expect to continue paying quarterly dividends during 2013 and we expect to review the dividend policy in the second quarter of 2013. At the current payout rate, we would expect to pay total cash dividends of approximately $40.1 million during 2013. In addition, while we do not currently anticipate repurchasing shares in 2013, we may repurchase common stock in the future. During 2011 and 2010, the Company repurchased a total of 4.3 million shares at an aggregate cost of $120.2 million, including commissions. Under our program, purchases can be made at open market prices or in private transactions, and repurchased shares are available for issuance under employee benefit and stock incentive plans, or may be retired. No shares of common stock were repurchased during the twelve months ended December 31, 2012. As of December 31, 2012, 393,816 shares remain eligible for repurchase.
We will continue to maintain a prudent level of liquidity as well as take market conditions for debt and equity securities into account. With the initiation of a dividend in early 2011, we are moving toward primarily utilizing the distribution of dividends to maintain a balanced capital structure, supplemented by share repurchases when appropriate. Our liquidity needs can fluctuate quickly based on fuel prices and other factors and we are continuing to make investments in new electric plant and other assets in order to reliably serve our customers. In light of these factors, we expect it will be a number of years before we achieve a dividend payout equivalent to industry average.
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 and net operating loss carryforwards, income tax payments are expected to be minimal in 2013.
We continually evaluate our funding requirements related to our retirement plans, other postretirement benefit plans, and decommissioning trust funds. We contributed $19.9 million and $13.8 million to our retirement plans during the twelve months ended December 31, 2012 and 2011, respectively. We also contributed $3.7 million and $2.2 million to our other postretirement benefit plan during the twelve months ended December 31, 2012 and 2011, respectively. We contributed $4.5 million and $8.3 million to our decommissioning trust funds for 2012 and 2011, 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 from operations has been our primary source for funding capital requirements. Cash from operations was $273.1 million in 2012 and $251.5 million in 2011. In 2012, cash from operations was impacted by a rate reduction in Texas. On April 17, 2012, the Council approved the settlement of our 2012 Texas retail rate case in PUCT Docket No. 40094. For Texas service areas outside the city limits of El Paso, the settlement was filed with the PUCT, and the PUCT approved the settlement on May 18, 2012. In the settlement, we agreed to a reduction in our non-fuel base rates of $15 million annually, with the decrease being allocated primarily to Texas commercial and industrial customer classes. The rate decrease was effective May 1, 2012, and our non-fuel base revenues were reduced by approximately $11.7 million in 2012 as a result of these lower rates. As part of the settlement we agreed to withdraw our request to reconcile fuel costs for the period from July 1, 2009, through September 30, 2011.
On December 6, 2012, we issued $150 million in aggregate principal amount of 3.30% senior notes due December 15, 2022. The gross proceeds from the issuance of the senior notes were $149.7 million, net of a $0.3 million discount before commissions and expenses and the effective interest rate was 3.43%. On August 28, 2012, we completed a refunding transaction related to our
4.80% 2005 Series A (El Paso Electric Company Palo Verde Project) Pollution Control Refunding Revenue Bonds totaling $59.2 million in which new pollution control bonds totaling $59.2 million were issued at a fixed rate of 4.50%. The bonds are unsecured and will mature in 2042. On August 28, 2012, we also completed a remarketing transaction related to our 4.00% 2002 Series A (El Paso Electric Company Four Corners Project) Pollution Control Refunding Revenue Bonds totaling $33.3 million in which new pollution control bonds totaling $33.3 million were issued at a fixed rate of 1.875%. These bonds were unsecured and mature in 2032 although they are subject to mandatory tender for purchase in 2017.
We maintain a revolving credit facility (“RCF”) for working capital and general corporate purposes and the financing of nuclear fuel through the RGRT. RGRT is the trust through which we finance our portion of nuclear fuel for Palo Verde and is consolidated in the Company's financial statements. The RCF has a term ending in September 2016. On March 29, 2012, the Company increased the aggregate unsecured borrowing available under the RCF from $200 million to $300 million. The terms of the agreement provide that amounts we borrow under the RCF may be used for working capital and general corporate purposes. The total amount borrowed for nuclear fuel by RGRT was $132.2 million at December 31, 2012, of which $22.2 million had been borrowed under the RCF and $110 million was borrowed through senior notes. Borrowings by RGRT for nuclear fuel were $123.4 million at December 31, 2011, of which $13.4 million had been borrowed under the RCF and $110 million was borrowed through senior notes. Interest costs on borrowings to finance nuclear fuel are accumulated by RGRT and charged to us as fuel is consumed and recovered from customers through fuel recovery charges. No borrowings were outstanding at December 31, 2012, under the RCF for working capital and general corporate purposes.
Cash from operations has also 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. Effective July 1, 2010, we can seek to revise our fixed fuel factor at least four months after our last revision except in the month of December based upon our approved formula which allows us to adjust fuel rates to reflect changes in costs of natural gas. On May 1, 2012, we implemented a reduced fixed fuel factor charged to our Texas retail customers. The reduced fixed fuel factor is based upon a formula that reflects current changes in prices for natural gas.
During the twelve months ended December 31, 2012, we had increased cash from operations when compared to the same period in 2011, which reflects an increase in the collection of deferred fuel revenues in 2012. During the twelve months ended December 31, 2012, the Company had an over-recovery, net of refunds, of $11.7 million as compared to an under-recovery of fuel costs, net of refunds, of $26.0 million during the twelve months ended December 31, 2011. At December 31, 2012, we had a net fuel over-recovery balance of $4.6 million, including $2.3 million in Texas and $2.3 million in New Mexico.
We believe we have adequate liquidity through our current cash balances, cash from operations and our revolving credit facility to meet all of our anticipated cash requirements for the next twelve months. In addition, we should continue to have access to the capital markets on favorable terms.
Contractual Obligations. Our contractual obligations as of December 31, 2012 are as follows (in thousands):
_____________________
(1)
We have three issuances of Senior Notes. In May 2005, we issued $400.0 million in aggregate principal amount of 6% Senior Notes due May 15, 2035. In June 2008, we issued $150.0 million in aggregate principal amount of 7.5% Senior Notes due March 15, 2038. In December 2012, we issued $150.0 million in aggregate principal amount of 3.3% Senior Notes due December 15, 2022.
(2)
We have four series of pollution control bonds which are scheduled for remarketing and/or mandatory tender, one in 2017, two in 2040, and one in 2042.
(3)
In 2010, the Company and RGRT entered into a Note Purchase Agreement for $110 million aggregate principal amount of senior notes consisting of: (a) $15 million aggregate principal amount of 3.67% RGRT Senior Notes, Series A, due August 15, 2015, (b) $50 million aggregate principal amount of 4.47% RGRT Senior Notes, Series B, due August 15, 2017 and (c) $45 million aggregate principal amount of 5.04% RGRT Senior Notes, Series C, due August 15, 2020.
(4)
This reflects obligations outstanding under the $300 million RCF. At December 31, 2012, $22.2 million was borrowed by RGRT for nuclear fuel. This balance includes interest based on actual interest rates at the end of 2012 and assumes this amount will be outstanding for the entire year of 2013.
(5)
Amount is based on the minimum volumes per the contract and market and/or contract price at the end of 2012. Gas obligation includes a gas storage contract and a gas transportation contract.
(6)
Some of the nuclear fuel contracts are based on a fixed price, adjusted for a market index. The index used here is the index at the end of 2012.
(7)
This obligation is based on our expected contributions and includes our minimum contractual funding requirements for the non-qualified retirement income plan and the other postretirement benefits for 2013. We have no minimum cash contractual funding requirement related to our retirement income plan for 2013. However, we may decide to fund at higher levels and expect to contribute $21.8 million and $4.0 million to our retirement plans and postretirement benefit plan, respectively, in 2013, as disclosed in Part II, Item 8, Notes to Consolidated Financial Statements, Note M, Employee Benefits. Minimum funding requirements for 2014 and beyond are not included due to the uncertainty of interest rates and the related return on assets.
(8)
These obligations represent funding amounts approved in PUCT Docket No. 40094 and NMPRC Case No. 09-00171-UT.
(9)
We 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, parking facilities and equipment 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 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. Under these rules, 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 $90.6 million and $89.3 million as of December 31, 2012 and 2011, respectively. A hypothetical 10% increase in interest rates would reduce the fair values of these funds by $0.7 million and $0.8 million based on their fair values at December 31, 2012 and 2011, respectively.
Equity Price Risk
Our decommissioning trust funds include marketable equity securities of approximately $92.0 million and $74.9 million at December 31, 2012 and 2011, respectively. A hypothetical 20% decrease in equity prices would reduce the fair values of these funds by $18.4 million and $15.0 million based on their fair values at December 31, 2012 and 2011, respectively. Declines in market prices could require that additional amounts be contributed to our decommissioning trusts to maintain minimum funding requirements. We will not have a requirement to expend monies held in trust before 2044 or a later period when we begin to decommission Palo Verde.
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. We also enter into 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, 2013, 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, 2012. 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, 2012, 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 42 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, 2012 and 2011, 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, 2012. We also have audited El Paso Electric Company’s internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). 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, 2012 and 2011, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2012, 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, 2012, 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, 2013
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 discontinued these activities in 2002. 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 D. The Company applies FASB guidance for regulated operations for all three of the jurisdictions in which it operates.
Extraordinary item. As discussed in the previous paragraph, FASB guidance for regulated operations requires the Company to show certain items as assets or liabilities on its balance sheet when the regulator provides assurance that these items will be charged to and collected from customers or refunded to customers. In the final order for the Public Utility Commission of Texas ("PUCT") Docket No. 37690, the Company was allowed to include the previously expensed loss on reacquired debt associated with the refinancing of first mortgage bonds in 2005 in its calculation of the weighted cost of debt to be recovered from its customers. The Company recorded the impacts of the re-application of FASB guidance for regulated operations to its Texas jurisdiction in 2006 as an extraordinary item. In order to establish this regulatory asset, the Company recorded an extraordinary gain of $10.3 million, net of income tax expense of $5.8 million, pursuant to the final order received from the PUCT, in its statements of operations for the quarter ended September 30, 2010. The regulatory asset will be amortized over the remaining life of the Company's 6% Senior Notes due in 2035.
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. Utility plant is generally reported at cost. The cost of renewals and betterments are capitalized and the costs of repairs and minor replacements are charged to the appropriate operating expense accounts. Depreciation is provided on a straight-line basis over the estimated remaining lives of the assets (ranging in average from 5 to 48 years). The average composite depreciation rate utilized in 2012, 2011 and 2010 was 2.64%, 2.80%, and 3.21%, respectively. When property subject to composite depreciation is retired or otherwise disposed of in the normal course of business, its 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
EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 E.
Impairment of Long-Lived Assets. 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. AFUDC is compounded on a monthly basis. The AFUDC rates used in 2012 and 2011 were 8.53% and 8.54%, respectively. The AFUDC rate utilized for the first six months of 2010 was 9.01% and 8.47% thereafter.
Asset Retirement Obligation. 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 conditioned on a future event that may or may not be within the control of an entity. See Note F. 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. 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 loss 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 O.
Derivative Accounting. Accounting for derivative instruments and hedging activities 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 O.
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 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 C.
Revenues. Revenues related to the sale of electricity are generally recorded when service is rendered or electricity is delivered to customers. The billing of electricity sales to retail customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. Unbilled revenues are estimated based on monthly generation volumes and by applying
EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
an average revenue/kWh to the number of estimated kWhs delivered but not billed. Accounts receivable included accrued unbilled revenues of $17.9 million and $19.6 million at December 31, 2012 and 2011, respectively. The Company presents revenues net of sales taxes in its consolidated statements of operations.
Allowance for Doubtful Accounts. The allowance for doubtful accounts represents the Company’s estimate of existing accounts receivable that will ultimately be uncollectible. The allowance is calculated by applying estimated write-off factors to various classes of outstanding receivables. The write-off factors used to estimate uncollectible accounts are based upon consideration of both historical collections experience and management’s best estimate of future collections success given the existing collections environment. Additions, deductions and balances for allowance for doubtful accounts for 2012, 2011 and 2010 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. 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. Certain temporary differences are accorded flow-through treatment by the Company's regulators and impact the Company's effective tax rate. FASB guidance requires that rate-regulated companies record deferred income taxes for temporary differences accorded flow-through treatment at the direction of the regulatory commission. The resulting deferred tax assets and liabilities are recorded at the expected cash flow to be reflected in future rates. Because the Company's regulators have consistently permitted the recovery of tax effects previously flowed-through earnings, the Company has recorded regulatory liabilities and assets offsetting such deferred tax 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 J.
Earnings per Share. 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 income is allocated to the weighted average number of 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 the weighted average number of 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 G.
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 G.
Pension and Postretirement Benefit Accounting. See Note M for a discussion of the Company’s accounting policies for its employee benefits.
Reclassification. Certain amounts in the consolidated financial statements for 2011 and 2010 have been reclassified to conform with the 2012 presentation.
EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
B. New Accounting Standards
In February 2013, the FASB issued new guidance (ASU 2013-02, Comprehensive Income (Topic 220)) to improve the reporting of reclassifications out of accumulated other comprehensive income (loss). ASU 2013-02 requires an entity to report the effect of significant reclassifications out of accumulated other comprehensive income (loss) on the respective line items in net income if the amount being reclassified is required under FASB guidance to be reclassified in its entirety to net income in the same reporting period. For other amounts that are not required under FASB guidance to be reclassified in their entirety to net income in the same reporting period, an entity is required to cross-reference other disclosures required under FASB guidance that provide additional detail about those amounts.
Substantially all of the information that ASU 2013-02 requires is already required to be disclosed elsewhere in the financial statements under FASB guidance. However, the new requirement about presenting information about amounts reclassified out of accumulated other comprehensive income (loss) and their corresponding effect on net income will present, in one place, information about significant amounts reclassified and, in some cases, cross-references to related footnote dislcosures. Currently, this information is presented in different places thoughout the financial statements. The Company will be required to present the corresponding effects of components reclassified out of accumulated other comprehensive income (loss) on net income with cross-references to other disclosures because FASB guidance does not require that all of the Company's components be reclassified from accumulated other comprehensive income (loss) to net income in their entirety in the same reporting period.
ASU 2013-02 is effective prospectively for reporting periods beginning after December 15, 2012 and early adoption is permitted. The Company will implement ASU 2013-02 in the first quarter of 2013.
C. 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 (sales for resale) transactions, transmission service and compliance with federally-mandated reliability standards. The decisions of the PUCT, NMPRC and the FERC are subject to judicial review.
Texas Regulatory Matters
2012 Texas Retail Rate Case. The Company filed a rate increase request with the PUCT, Docket No. 40094, the City of El Paso, and other Texas cities on February 1, 2012. The rate filing was made in response to a resolution adopted by the El Paso City Council (the "Council") requiring the Company to show cause why its base rates for customers in the El Paso city limits should not be reduced. The filing at the PUCT also included a request to reconcile $356.5 million of fuel expense for the period July 1, 2009 through September 30, 2011.
On April 17, 2012, the Council approved the settlement of the Company's 2012 Texas retail rate case and fuel reconciliation in PUCT Docket No. 40094. The PUCT issued a final order approving the settlement on May 23, 2012.
Under the terms of the settlement, among other things, the Company agreed to:
•
A reduction in its non-fuel base rates of $15 million annually, with the decrease being allocated primarily to Texas retail commercial and industrial customer classes. The rate decrease was effective as of May 1, 2012;
•
Revised depreciation rates for the Company's gas-fired generating units and for transmission and distribution plant that lower depreciation expense by $4.1 million annually;
•
Continuation of the 10.125% return on equity for the purpose of calculating the allowance for funds used during construction; and
•A
two-year amortization of rate case expenses, none of which will be included in future regulatory proceedings.
EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
As part of the settlement, the Company agreed to withdraw its request to reconcile fuel costs for the period from July 1, 2009 through September 30, 2011. The Company will file a fuel reconciliation request covering the period beginning July 1, 2009 and ending no later than June 30, 2013 by December 31, 2013 or as part of its next rate case, if earlier.
Fuel and Purchased Power Costs. The Company's actual fuel costs, including purchased power energy costs, are recoverable from its customers. The PUCT has adopted a fuel cost recovery rule ("Texas Fuel Rule") that allows the Company to seek periodic adjustments to its fixed fuel factor. In 2010, the Company received approval to implement a formula to determine its fuel factor which adjusts natural gas and purchased power to reflect natural gas futures prices. The Company can 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 fuel costs 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 fuel cost recovery 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.
During 2012, the Company filed the following petition with the PUCT to refund recent fuel cost over-recoveries, due primarily to fluctuations in natural gas markets and consumption levels. The table summarizes the docket number assigned by the PUCT, the date the Company filed the petition and the date a final order was issued by the PUCT approving the refund to customers. The fuel cost over-recovery period represents the months in which the over-recoveries took place, and the refund period represents the billing month in which customers received the refund amounts shown, including interest:
The Company filed the following petition in 2012 with the PUCT to revise its fixed fuel factor pursuant to the fuel factor formula authorized in PUCT Docket No. 37690:
Generation CCN Filing. On May 2, 2012, the Company filed a petition with the PUCT requesting a CCN to construct a new generating facility to be located at a new plant site, the Montana Power Station, in east El Paso. The new facility will initially consist of two 88 MW simple-cycle aeroderivative combustion turbines, which will be powered by natural gas. The first unit is scheduled to become operational in 2014. On December 13, 2012, the PUCT issued a Final Order approving the requested CCN.
The Company has also filed two air permit applications for the Montana Power Station. One application was filed with the Texas Commission on Environmental Quality ("TCEQ") and a contested hearing on the merits of the application is scheduled for May 1, 2013, before the State Office of Administrative Hearings in Austin, Texas. Several parties, representing affected individuals as defined by TCEQ, have requested status in the hearing. The second air permit application is an EPA greenhouse permit application which remains under review. A final permit is expected from the EPA by August 2013 if there is no appeal. While the Company believes that the Montana Power Station complies with all air regulations, it cannot predict the final outcome of these applications.
Energy Efficiency Cost Recovery Factor ("EECRF"). On April 30, 2012, the Company filed an application to revise its EECRF and to establish revised energy efficiency goals and cost caps, pursuant to the Public Utility Regulatory Act ("PURA") Section 39.905. On September 20, 2012, the PUCT approved a unanimous settlement resolving all issues. The settlement allows the Company to recover $5.5 million in energy efficiency costs, revised the Company’s demand and energy goals and granted the Company’s request to increase its 2013 EECRF effective with billings in January 2013.
Military Base Discount Recovery Factor ("MBDRF"). On July 16, 2012, the Company filed a petition to revise its MBDRF. On November 16, 2012, the PUCT approved a unanimous stipulation and settlement, with the City of El Paso and Staff, which provides for the surcharge to be increased from 0.936% to 1.055% of customer bills. The revised MBDRF is designed to recover estimated discounts and the recovery of past under-recoveries spread over two years, totaling $4.6 million and is effective with December 2012 billings.
EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Other Required Approvals. The Company has obtained all other required approvals for recovery of fuel costs through fixed fuel factors, other tariffs and approvals as required by the PURA and the PUCT.
New Mexico Regulatory Matters
2009 New Mexico Stipulation. On December 10, 2009, the NMPRC issued a final order conditionally approving the stipulated rates in NMPRC Case No. 09-00171-UT. The stipulated rates went into effect with January 2010 bills.
Generation CCN Filing. On May 2, 2012, the Company filed a petition with the NMPRC requesting a CCN to construct a new generation facility to be located at a new plant site, the Montana Power Station, in east El Paso. The NMPRC approved the CCN on January 23, 2013.
2012 Annual Procurement Plan Pursuant to the Renewable Energy Act. On June 29, 2012, the Company filed its application for approval of its 2012 Annual Procurement Plan pursuant to the New Mexico Renewable Energy Act. On December 11, 2012, the NMPRC issued a final order approving the renewable procurement plan with modifications recommended by the Hearing Examiner. The plan sets out the Company's procurement of renewable resources and estimated costs for 2013 and 2014 to meet Renewable Portfolio Standards ("RPS") and resource diversity requirements. The approved plan provides for the RPS and diversity requirements for 2013 and 2014 to be met with a combination of previously approved resources and excused the Company from a requirement to make-up a deficiency in the "other" diversity requirement for 2011 and from meeting the "other" diversity requirement for the 2013 and 2014 compliance years. Costs for purchases of renewable energy delivered to the Company are recovered through the New Mexico Fuel and Purchased Power Cost Adjustment Clause ("FPPCAC") and purchases of renewable energy credits are recovered through base rates.
Long-Term Purchased Power Agreement with Macho Springs. On November 21, 2012, the Company filed an application with the NMPRC requesting approval of a Long-Term Purchase Power Agreement ("LTPPA") with Macho Springs Solar, LLC ("Macho Springs") to purchase energy from a 50 MW solar facility to be constructed by Macho Springs in the Company's New Mexico service territory. The Company also seeks approval of the recovery of costs associated with the LTPPA through the Company's FPPCAC. The hearing is scheduled to begin March 14, 2013 and a final order is expected by the end of May 2013.
Other Required Approvals. The Company has obtained all other required approvals for other tariffs, securities transactions, long-term resource plans, recovery of energy efficiency costs through a base rate rider and other approvals as required by the NMPRC.
Federal Regulatory Matters
Public Service Company of New Mexico's (“PNM”) 2010 Transmission Rate Case. On October 27, 2010, PNM filed a Notice of Transmission Rate Changes for transmission delivery services provided by PNM. These rates went into effect on June 1, 2011. The Company takes transmission service from PNM. On January 2, 2013, the FERC issued a letter order approving a unanimous stipulation and agreement. Pursuant to the stipulation, on January 31, 2013, PNM refunded $1.9 million, for amounts that PNM collected since June 1, 2011, in excess of settlement rates. This amount was recorded in the fourth quarter of 2012 as a reduction of transmission expense.
Other Required Approvals. The Company has obtained all required approvals for rates and tariffs, securities transactions and other approvals as required by the FERC.
Department of Energy ("DOE"). 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 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 E for discussion of spent fuel storage and disposal costs.
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Sales for Resale
The Company provides firm capacity and associated energy to the RGEC pursuant to an ongoing contract with a two-year notice to terminate provision. The Company also provides network integrated transmission service to RGEC pursuant to the Company's Open Access Transmission Tariff ("OATT"). The contract includes a formula-based rate that is 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.
D. 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)
No specific return on investment is required since related assets and liabilities, including accumulated deferred income taxes and reclamation liability, offset.
(b)
The amortization period for this asset is based upon the life of the associated assets.
(c)
This item is recovered as a component of the weighted cost of debt and amortized over the life of the related debt issuance.
(d)
This item is recovered through fuel recovery mechanisms.
(e)
This item is recovered or credited through an annual recovery factor.
(f)
This item is included in rate base which earns a return on investment.
(g)
Amortization period is anticipated to be established in next general rate case.
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(h)
This item represents the net asset related to the military discount which is recovered from non-military customers through a recovery factor.
(i)
This item is excluded from rate base.
E. 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, 2012 (in thousands):
Amortization of intangible plant (software) is provided on a straight-line basis over the estimated useful life of the asset (ranging from 5 to 10 years). The table below presents the actual and estimated amortization expense for intangible plant for the previous three years and 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.
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, 2012 and 2011 is as follows (in thousands):
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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.
License Extension. On April 21, 2011, the Company, along with the other Palo Verde Participants, was notified that the NRC had renewed the operating licenses for all three units at Palo Verde. The renewed licenses for Units 1, 2 and 3 now expire in 2045, 2046 and 2047, respectively. The extension of the operating leases reduced the Company's annual depreciation and amortization expense by approximately $11.0 million and reduced the Company's annual accretion expense by approximately $4.4 million. For 2011, the extension of the operating leases had the effect of reducing depreciation and amortization expense by approximately $8.2 million and reducing the accretion expense on the Palo Verde asset retirement obligation by approximately $3.1 million.
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 and is required to maintain a minimum accumulation and 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, 2012, the Company’s decommissioning trust fund had a balance of $187.1 million, which is above its minimum funding level. The Company monitors the status of its decommissioning funds and adjust its deposits, if necessary.
Decommissioning costs are estimated every three years based upon engineering cost studies performed by outside engineers retained by APS. On March 30, 2011, the Palo Verde Participants approved the 2010 Palo Verde decommissioning study (the “2010 Study”). The 2010 Study reflects the extension of the operating license from 40 years to 60 years. The 2010 Study estimated that the Company must fund approximately $357.4 million (stated in 2010 dollars) to cover its share of decommissioning costs which was an increase in decommissioning costs of $33.0 million (stated in 2010 dollars) from the 2007 Palo Verde decommissioning study (the “2007 Study”). The net effect of these changes lowered the asset retirement obligation by $41.7 million and lowered annual expenses after March 2011. Although the 2010 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.
Spent Nuclear Fuel and Waste Disposal. 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 failed to begin accepting Palo Verde's spent nuclear fuel, and APS (on behalf of itself and the other Palo Verde participants) filed a lawsuit for DOE's breach of the spent nuclear fuel contract in the U.S. Court of Federal Claims. The Court of Federal Claims ruled in favor of APS and in October 2010 awarded $30.0 million in damages to the Palo Verde participants for costs incurred through December 2006. In October 2010, the Company received $4.8 million, representing its share of the award. The majority of the award was refunded to customers through the applicable fuel adjustment clauses. On December 19, 2012, APS, acting on behalf of itself and the participant owners of Palo Verde, filed a second breach of contract lawsuit against the DOE. This lawsuit seeks to recover damages incurred due to DOE's failure to accept Palo Verde's spent nuclear fuel for the period beginning January 1, 2007 through June 30, 2011.
The DOE had planned to meet its disposal obligations by designing, licensing, constructing, and operating a permanent geologic repository at Yucca Mountain, Nevada. In March 2010, the DOE filed a motion to dismiss with prejudice its Yucca
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Mountain construction authorization application that was pending before the NRC. Several interested parties have intervened in the NRC proceeding, and the proceeding has not been conclusively decided by the NRC or the courts. Additionally, a number of interested parties have filed a variety of lawsuits in different jurisdictions around the country challenging the DOE's authority to withdraw the Yucca Mountain construction authorization application. None of these lawsuits have been conclusively decided by the courts. In addition, the NRC's rulemaking regarding temporary storage and permanent disposal of high level nuclear waste and spent nuclear fuel has been challenged and is being reworked. The Company cannot predict when spent fuel shipments to the DOE will commence.
APS and the Company believe 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. The Company expects to incur significant costs for on-site spent fuel storage during the life of Palo Verde which 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.
NRC Oversight of the Nuclear Energy Industry in the Wake of the Earthquake and Tsunami in Japan. 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. Following the March 11, 2011 earthquake and tsunami in Japan, which caused significant damage to the Fukushima Daiichi Nuclear Power Station, the NRC launched a two-pronged review of U.S. nuclear power plant safety. With respect to Palo Verde, the NRC issued two orders requiring safety enhancements regarding: (1) mitigation strategies to respond to extreme natural events resulting in the loss of power at plants; and (2) enhancement of spent fuel pool instrumentation. The NRC has also requested information pertaining to re-evaluations of seismic and flooding hazards, communications, and staffing during events affecting multiple reactors at a site. Palo Verde has budgeted $14 million, total project, in modifications for the 2013 capital budget relating to the NRC requirements. Until further action is taken by the NRC as a result of this event, the Company cannot predict any additional financial or operational impacts on Palo Verde.
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, which is 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 is covered 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 $2.8 billion, a substantial portion of which must first be applied to stabilization and decontamination. The Company has also secured insurance against portions of any increased cost of generation or purchased power and business interruption resulting from a sudden and unforeseen outage of any of the three units. The insurance coverage discussed in this and the previous paragraph is subject to certain policy conditions and exclusions. A mutual insurance company whose members are utilities with nuclear facilities issues these policies. If losses at any nuclear facility covered by this mutual insurance company were to exceed the accumulated funds for these insurance programs, the Company could be assessed retrospective premium adjustments of up to $9.8 million for the current policy period.
F. 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 retirement obligations 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
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 2012 ARO liability for Palo Verde is based upon the estimated cost of decommissioning the plant from the 2010 Palo Verde decommissioning study. See Note E. 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. 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 that are legally restricted to settling its ARO at Palo Verde. The fair value of the funds at December 31, 2012 is $187.1 million.
FASB guidance requires the Company to revise its previously recorded ARO for any changes in estimated cash flows including changes in estimated probabilities related to timing of settlements. 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. In April 2011, the Company implemented the 2010 Palo Verde decommissioning study, and as a result, revised its ARO related to Palo Verde to (i) increase estimated cash flows from the 2007 Study to the 2010 Study, and (ii) change estimated probabilities due to Palo Verde license extension (see Note E). The assumptions used to calculate the original Palo Verde ARO liability and the revised Palo Verde ARO liability are as follows:
A roll forward of the Company's ARO liability is presented below and revisions to estimates include both the increase to estimated cash flows and the change in estimated probabilities for life extension due to the approval of a Palo Verde license extension in 2011 and the change in the estimated probability of extending the Four Corners' original lease term in 2012.
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.
G. 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
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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, 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 2012:
The intrinsic value of stock options exercised in 2012, 2011 and 2010 were $0.6 million, $1.0 million and $1.3 million, respectively. No options were forfeited, vested or expired during 2012, 2011 and 2010.
All stock options outstanding have vested. No compensation cost was recognized in 2010, 2011 and 2012 for stock options and there is no unrecognized compensation expense related to stock options.
Restricted Stock. The Company has awarded restricted stock under its long-term incentive plan. 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.
The expense, deferred tax benefit, and current tax expense recognized related to restricted stock awards in 2012, 2011 and 2010 is presented below (in thousands):
_____________________
(a) Any capitalized costs related to these expenses would be less than $0.1 million for all years.
The aggregate intrinsic value and fair value at grant date of restricted stock which vested in 2012, 2011 and 2010 is presented below (in thousands):
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The unvested restricted stock transactions for 2012 are presented below:
_______________________
(a) The unrecognized compensation expense is expected to be recognized over the weighted average remaining contractual term of the outstanding restricted stock of approximately one year.
(b) Forfeitures include 79,489 shares with a weighted average grant date fair value of $27.46 which were forfeited by the March 2, 2012 resignation of the Company's former Chief Executive Officer.
The weighted average fair value per share at grant date for restricted stock awarded during 2012, 2011 and 2010 were:
The holder of a restricted stock award has rights as a shareholder of the Company, including the right to vote and receive cash dividends on restricted stock.
Performance Shares. The Company has granted performance share awards to certain officers under the Company’s existing long-term incentive plan, which provides 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.
Detail of performance shares vested follows:
In 2013, 2014 and 2015, subject to meeting certain performance criteria, additional performance shares could be awarded. In accordance with FASB guidance related to stock-based compensation, the Company 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. Excluding the 64,275 shares that vested on January 1, 2013, the actual number of shares to be issued can range from zero to 170,366 shares.
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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 outstanding performance share awards at the 100% performance level is summarized below:
_______________________
(a) The unrecognized compensation expense is expected to be recognized over the weighted average remaining contractual term of the awards of approximately one year.
(b) Forfeitures include 132,914 shares with a weighted average grant date fair value of $23.80 which were forfeited by the March 2, 2012 resignation of the Company's former Chief Executive Officer.
A summary of information related to performance shares for 2012, 2011 and 2010 is presented below:
_____________________
(a) Includes cumulative adjustments for forfeiture of performance share awards by certain executives.
Repurchase Program
No shares of common stocks were repurchased during the twelve months ended December 31, 2012. Detail regarding the Company's stock repurchase program are presented below:
______________________
(a)
Represents repurchased shares and cost since inception of the stock repurchase program in 1999.
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(b)
Shares repurchased does not include 86,735 treasury shares related to employee compensation arrangements outside of the Company's repurchase programs.
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.
Dividend Policy
On December 28, 2012, the Company paid $10.0 million in quarterly cash dividends to shareholders. The Company paid a total of $38.9 million and $27.2 million in cash dividends during the twelve months ended December 31, 2012 and 2011. On January 17, 2013, the Board of Directors declared a quarterly cash dividend of $0.25 per share payable on March 29, 2013 to shareholders of record on March 14, 2013.
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Basic and Diluted Earnings Per Share
FASB guidance requires the Company 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 and diluted earnings per share are presented below:
The amount of restricted stock awards, performance shares and stock options excluded from the calculation of the diluted number of common shares outstanding because their effect was antidilutive is presented below:
_____________________
(a)
Performance shares were excluded from the computation of diluted earnings per share as no payouts would have been required based upon performance at the end of each corresponding period. These amounts assume a 100% performance level payout.
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H. Accumulated Other Comprehensive Loss
Accumulated other comprehensive loss consists of the following components (in thousands):
I. Long-Term Debt and Financing Obligations
Outstanding long-term debt and financing obligations are as follows:
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_____________________
(1)
Pollution Control Bonds (“PCBs”)
The Company has four series of tax exempt unsecured PCBs in aggregate principal amount of $193.1 million. In August 2012, the 4.80% 2005 Series A (El Paso Electric Company Palo Verde Project) Pollution Control Refunding Revenue Bonds with an aggregate principal amount of $59.2 million was refunded at a fixed rate of 4.50% and will mature on August 1, 2042. The 4.00% 2002 Series A (El Paso Electric Company Four Corners Project) Pollution Control Refunding Revenue Bonds with an aggregate principal amount of $33.3 million was remarketed in August 2012 at a fixed rate of 1.875%, until September 1, 2017 when the bonds are subject to mandatory tender for purchase. These bonds will mature on June 1, 2032.
(2)
Senior Notes
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. The 6.00% senior notes have an aggregate principal amount of $400.0 million and were issued in May 2005. The proceeds, net of a $2.3 million discount, were used to fund the retirement of the Company's first mortgage bonds. The Company amortizes the loss associated with a cash flow hedge recorded in accumulated other comprehensive income to earnings as interest expense over the life of the 6.00% senior notes. See Note O, "Financial Instruments and Investments - Treasury Rate Locks". This amortization is included in the effective interest rate of the 6.00% senior notes.
The 7.50% senior notes have an aggregate principal amount of $150.0 million and were issued in June 2008. The proceeds, net of a $1.3 million discount, were used to repay short-term borrowings of $44.0 million, fund capital expenditures and for other general corporate purposes.
The 3.30% senior notes have an aggregate principal amount of $150.0 million, were issued in December 2012 and will mature on December 15, 2022. The gross proceeds, net of a $0.3 million discount, will be used to fund construction expenditures and for working capital and general corporate purposes.
(3)
RGRT Senior Notes
On August 17, 2010, the Company and RGRT, a Texas grantor trust through which the Company finances its portion of fuel for Palo Verde, entered into a Note Purchase Agreement (the “Agreement”) with various institutional purchasers. Under the terms of the Agreement, RGRT sold to the purchasers $110 million aggregate principal amount of senior notes (the "Notes"). The Company guarantees the payment of principal and interest on the Notes. In the Company’s financial statements, the assets and liabilities of the RGRT are reported as assets and liabilities of the Company.
RGRT will pay interest on the Notes on February 15 and August 15 of each year until maturity. RGRT may redeem the Notes, in whole or in part, at any time at a redemption price equal to 100% of the principal amount to be redeemed together with the interest on such principal amount accrued to the date of redemption, plus a make-whole amount based on the prevailing market interest rates. The Agreement requires compliance with certain covenants, including a total debt to capitalization ratio. The Company was in compliance with these requirements throughout 2012.
The sale of the Notes was made by RGRT in reliance on a private placement exemption from registration under the Securities Act of 1933, as amended.
The proceeds of $109.4 million, net of issuance costs, from the sale of the Notes was used by RGRT to repay amounts borrowed under the revolving credit facility and will enable future nuclear fuel financing requirements of RGRT to be met with a combination of the Notes and amounts borrowed from the revolving credit facility.
(4)
Revolving Credit Facility
On March 29, 2012, the Company and RGRT entered into the Incremental Facility Assumption Agreement ("the Assumption Agreement") related to the revolving credit agreement (the “RCF”) with JP Morgan Chase Bank, N.A., as administrative agent and issuing bank, and Union Bank, N.A., as syndication agent, and various lending banks party thereto. The Assumption Agreement provides for the Company's exercise in full of the accordian feature provided for under the RCF, increasing the
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aggregate unsecured borrowing available from $200 million to $300 million. The RCF has a term ending September 2016. No other material modifications were made to the terms and conditions of the RCF.
The RCF provides that amounts borrowed by the Company may be used for, among other things, working capital and general corporate purposes. Any amounts borrowed by RGRT may be used, among other things, to finance the acquisition and processing of nuclear fuel. Amounts borrowed by RGRT are guaranteed by the Company and the balance borrowed under the RCF is recorded as short-term borrowings on the consolidated balance sheet. The RCF is unsecured. The RCF requires compliance with certain covenants, including a total debt to capitalization ratio. The Company was in compliance with these requirements throughout 2012. As of December 31, 2012, the total amount borrowed by RGRT was $22.2 million for nuclear fuel under the RCF. No borrowings were outstanding under this facility for working capital and general corporate purposes. The weighted average interest rate on the RCF was 1.5% as of December 31, 2012.
As of December 31, 2012, the scheduled maturities for the next five years of long-term debt are as follows (in thousands):
The $22.2 million outstanding on the RCF for nuclear fuel financing purposes is anticipated to be paid in 2013.
J. Income Taxes
The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and liabilities at December 31, 2012 and 2011 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 tax expense for 2012, 2011 and 2010 as follows (in thousands):
Current federal income tax expense for 2010 reflects taxes accrued under the alternative minimum tax (“AMT”). Deferred federal income tax for 2010 includes an offsetting AMT benefit of $10.2 million. There was no offsetting AMT benefit for 2012 or 2011. As of December 31, 2012, the Company had $21.6 million of AMT credit carryforwards that have an unlimited life. As of December 31, 2012, the Company had tax loss carryforwards of $7.7 million and $0.1 million that have lives of 20 years and 5 years, respectively.
Income tax provisions differ from amounts computed by applying the statutory federal income tax rate of 35% to book income before federal income tax as follows (in thousands):
The 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 2008 and in the state jurisdictions for years prior to 1998. The Company is currently under audit in the federal jurisdiction for tax years 2009 through 2012 and in Texas for 2007. A deficiency notice relating to the Company’s 1998 through 2003 and 2006 and 2007 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.
On March 23, 2010, the PPACA was signed into law. A major provision of the law is that, beginning in 2013, the income tax deductions for the cost of providing certain prescription drug coverage will be reduced by the amount of the Medicare Part D
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subsidies received. The Company was required to recognize the impacts of the tax law change at the time of enactment and recorded a one-time non-cash charge to income tax expense of approximately $4.8 million in the first quarter of 2010.
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 change was included in the 2009 federal income tax return, with additional amounts included in the 2010 federal income tax return. In August of 2012, the Company filed a change of accounting method with the IRS, effectively adopting the safe harbor provisions of Rev. Proc 2011-43 related to units of property for capitalized tax assets. The change was included in the 2011 federal income tax return. The Company recorded an additional unrecognized tax position of $1.6 million, $2.2 million and $6.3 million, in 2012, 2011, 2010, respectively, related to the changes in accounting method in 2009 through 2012. An additional unrecognized tax position may be recognized after the IRS audits the 2009 through 2012 tax returns. The Company recorded an unrecognized tax position of $1.4 million in 2012 related to depreciation amounts deducted in prior year Texas franchise tax returns. A reconciliation of the December 31, 2012, 2011 and 2010 amount of unrecognized tax benefits is as follows (in thousands):
If recognized, $1.2 million of the unrecognized tax position at December 31, 2012, would affect the effective tax rate. The Company recognized income tax expense for an unrecognized tax position of $1.5 million for the year ended December 31, 2012.
The Company recognizes in tax expense interest and penalties related to tax benefits that have not been recognized. During the years ended December 31, 2012 and 2010, the Company recognized a benefit of $0.3 million and $0.1 million, respectively, in interest. For the year ended December 31, 2011, the Company recognized interest expense of $0.2 million. The Company had approximately $0.1 million and $0.4 million accrued for the payment of interest and penalties at December 31, 2012, and 2011, respectively.
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K. Commitments, Contingencies and Uncertainties
Power Purchase and Sale Contracts
To supplement its own generation and operating reserves and to meet required renewable portfolio standards, the Company engages in firm power purchase arrangements which may vary in duration and amount based on evaluation of the Company’s resource needs, the economics of the transactions, and specific renewable portfolio requirements. The Company had entered into the following significant agreements with various counterparties for forward firm purchases and sales of electricity:
The Company has a Power Purchase and Sale Agreement with Freeport-McMoran Copper and Gold Energy Services LLC (“Freeport”) which provides for Freeport 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 the quantities noted in the table above 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 through December 2013. The contract was approved by the FERC and continues through December 31, 2021.
The Company entered into an agreement in 2009 to purchase capacity and unit contingent energy during 2010 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 entered into a contract with Shell on May 17, 2010 to extend the term of the capacity and unit contingent energy purchase from January 1, 2011 through September 30, 2014.
The Company entered into a 20-year contract with NRG Solar Roadrunner LLC (“NRG”) for the purchase of all of the output of a solar photovoltaic plant built in southern New Mexico which began commercial operation in August 2011. The Company has a 25-year purchase power agreement with Hatch Solar Energy Center I, LLC for a solar photovoltaic project located in southern New Mexico which began commercial operation in July 2011. The Company has 25-year purchase power agreements to purchase all of the output of two additional solar photovoltaic projects located in southern New Mexico, SunEdison 1 and SunEdison 2 which achieved commercial operation on June 25, 2012 and May 2, 2012, respectively. The Company entered into these contracts to help meet its renewable portfolio requirements.
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”). The contract includes a formula-based rate that is 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.
Environmental Matters
General. The Company is subject to extensive laws, regulations and permit requirements with respect to air, soil and water quality, waste management and disposal, natural resources and other environmental matters by federal, state, regional, tribal and local authorities. Failure to comply with such laws, regulations and requirements can result in actions by authorities or other third parties that might seek to impose on the Company administrative, civil and/or criminal penalties or other sanctions. In addition,
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releases of pollutants or contaminants into the environment can result in costly cleanup liabilities. These laws, regulations and requirements are subject to change through modification or reinterpretation, or the introduction of new laws and regulations and, as a result, the Company may face additional capital and operating costs to comply. Certain key environmental issues, laws and regulations facing the Company are described further below.
Air Emissions. The U.S. Clean Air Act ("CAA"), associated regulations and comparable state laws and regulations relating to air emissions impose, among other obligations, limitations on pollutants generated during the Company's operations, including sulfur dioxide ("SO2"), particulate matter ("PM"), nitrogen oxides ("NOx") and mercury.
Clean Air Interstate Rule/Cross State Air Pollution Rule. The U.S. Environmental Protection Agency's ("EPA") Clean Air Interstate Rule ("CAIR"), as applied to the Company, involves requirements to limit emissions of NOx and SO2 from certain of the Company's power plants in Texas and/or purchase allowances representing other parties' emissions reductions since 2009. While the U.S. Court of Appeals for the District of Columbia Circuit voided CAIR in 2008, such appellate court in August 2012 also vacated the EPA’s proposed replacement, called the Cross-State Air Pollution Rule (“CSAPR”). The EPA is expected to propose a CSAPR replacement rule, which if finalized and upheld, would also replace CAIR. The timing and substance of any final CAIR replacement is currently unknown and until promulgated and upheld, the Company remains subject to CAIR. The annual reconciliation to comply with CAIR is due by March 31 of the following year. The Company has purchased allowances and expensed the following costs to meet its annual requirements (in thousands):
National Ambient Air Quality Standards. Under the CAA, the EPA sets National Ambient Air Quality Standards ("NAAQS") for six criteria emissions considered harmful to public health and the environment, including PM, NOx, carbon monoxide ("CO") and SO2. NAAQS must be reviewed by the EPA at five-year intervals. In 2010, the EPA strengthened the NAAQS for both NOx and SO2. In December 2012, the EPA strengthened the NAAQS for fine PM, and it is likely to propose more stringent ozone NAAQS in 2013. The Company continues to evaluate what impact these final and proposed NAAQS could have on its operations. If the Company is required to install additional equipment to control emissions at its facilities, the revised NAAQS could have a material impact on its operations and consolidated financial results.
Utility MACT. The operation of coal-fired power plants, such as the Company's Four Corners plant, results in emissions of mercury and other air toxics. In December 2011, the EPA finalized Mercury and Air Toxics Standards (known as the "Utility MACT") for oil- and coal-fired power plants, which requires significant reductions in emissions of mercury and other air toxics. Several challenges are being made to this rule. These challenges notwithstanding, companies impacted by the new standards will have up to three (and some cases, four) years to comply. Information from the Four Corners plant operator, APS, indicates that APS believes Units 4 and 5 will require no additional modifications to achieve compliance with the Utility MACT standards; however, further testing and evaluation are planned.
Other Laws and Regulations. In addition, Four Corners, is, or may in the future be, required to comply with various other environmental laws and regulations and involved in various other legal proceedings related to such laws and regulations, which compliance and proceedings could result in increased costs to us. For example, Four Corners will be required to install pollution control equipment that constitutes the best available retrofit technology to lessen the impacts of emissions on visibility surrounding the plant, the costs of which could be material.
Climate Change. The U.S. federal government has either considered, proposed and/or finalized legislation or regulations limiting greenhouse gas ("GHG") emissions, including carbon dioxide. In particular, the U.S. Congress is expected to consider legislation to restrict or regulate GHG emissions in the next few years. In the past few years, the EPA began using the CAA to limit carbon dioxide and other GHG emissions, such as the 2009 GHG Reporting Rule and the EPA’s sulfur hexafluoride ("SF6") reporting rule, both of which the Company is subject, as well as the EPA’s 2010 so-called Tailoring Rule which rule could impose significant obligation and costs on power plant owners and operators. During the second term of the Obama Administration, the EPA is expected to propose further regulations targeting GHG emissions, including from existing power plants at some point in
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the future. In addition, almost half the U.S. states, either individually and/or through multi-state regional initiatives, have begun to consider how to address GHG emissions and have developed, or are actively considering the development of emission inventories or regional GHG cap and trade programs. While 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 more on coal-fired generation, current and future legislation and regulation of GHGs or any future related litigation could impose significant costs and/or operating restrictions on the Company, reduced demand for the power the Company generates and/or require the Company to purchase rights to emit GHGs, any of which could have a material adverse effect on the Company's 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 the Company's 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 believes that material effects on the Company's business or results of 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, the Company believes it is impossible to meaningfully quantify the costs of these potential impacts at present.
Environmental Litigation and Investigations. Since 2009, the EPA and certain environmental organizations have been scrutinizing, and in some cases, have filed lawsuits, relating to certain air emissions and air permitting matters from or of Four Corners. Since July 2011, the U.S. Department of Justice ("DOJ"), on behalf of the EPA, and APS have been engaged in substantive settlement negotiations in an effort to resolve the pending matters. The allegations being addressed through settlement negotiations are that APS failed to obtain the necessary permits and install the controls necessary under the CAA to reduce SO2, NOx, and PM, and that defendants failed to obtain an operating permit under Title V of the CAA that reflects applicable requirements imposed by law. In March 2012, the DOJ provided APS with a draft consent decree to settle the EPA matter, which decree contains specific provisions for the reduction and control of NOx, SO2, and PM, as well as provisions for a civil penalty, and expenditures on environmental mitigation projects with an emphasis on projects that address alleged harm to the Navajo Nation. Settlement discussions are on-going.
Similar to other utilities in the western half of the U.S., the Company received notice that Earthjustice filed a lawsuit in the United States District Court for New Mexico on October 4, 2011 for alleged violations of the Prevention of Significant Deterioration ("PSD") provisions of the CAA related to Four Corners. On January 6, 2012, Earthjustice filed a First Amended Complaint adding claims for violations of the CAA's New Source Performance Standards ("NSPS") program. Among other things, the plaintiffs seek to have the court enjoin operations at Four Corners until APS applies for and obtains any required PSD permits and complies with the referenced NSPSs. The plaintiffs further request the court to order the payment of civil penalties, including a beneficial mitigation project. On April 2, 2012, APS and the other Four Corners' participants filed motions to dismiss with the court. Earthjustice filed their response briefs on May 16, 2012. APS filed reply briefs on June 22, 2012. Utility Air Regulatory Group filed an amicus brief, and plaintiffs were allowed until July 23, 2012 to respond to that amicus brief. In November 2012, the parties filed a joint motion to stay the proceedings to enable settlement discussions, and the motion was granted staying the case until March 2013. The Company is unable to predict the outcome of this litigation.
Lease Agreements
The Company leases 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, parking facilities and equipment 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.
The Company's total annual rental expense related to operating leases was $1.3 million for 2012 and $1.1 million for 2011 and 2010. As of December 31, 2012, the Company’s minimum future rental payments for the next five years are as follows (in thousands):
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Union Matters
The collective bargaining agreement with existing union employees expires in September 2013 and the Company anticipates entering into negotiations on a new collective bargaining agreement prior to the expiration of the current contract.
L. 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 C and Note K for discussion of the effects of government legislation and regulation on the Company.
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M. Employee Benefits
Retirement Plans
The Company’s Retirement Income Plan (the “Retirement Plan”) covers employees who have completed one year of service with the Company and work at least a minimum number of hours each year. The Retirement Plan is a qualified noncontributory defined benefit plan. Upon retirement or death of a vested plan participant, assets of the Retirement Plan are used to pay benefit obligations under the Retirement Plan. Contributions from the Company are at least the minimum funding amounts required by the IRS under provisions of the Retirement Plan, as actuarially calculated. The assets of the Retirement Plan are invested in equity securities, debt securities and cash equivalents and are managed by professional investment managers appointed by the Company.
The Company has two non-qualified retirement plans that are non-funded defined benefit plans. The Company's Supplemental Retirement Plan covers certain former employees and directors of the Company. The other plan, the Excess Benefit Plan was adopted in 2004 and 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. The Company complies with FASB guidance on disclosure for pension and other post-retirement plans that requires 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):
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Amounts recognized in the Company’s consolidated balance sheets consist of the following (in thousands):
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:
The Company reassesses various actuarial assumptions at least on an annual basis. The discount rate is reviewed at each measurement date. The discount rate used to measure obligations is based on a spot rate yield curve that matches projected future payments with the appropriate interest rate applicable to the timing of the projected future benefit payments. A 1% increase in the discount rate would decrease the December 31, 2012 retirement plans' projected benefit obligation by 12.7%. A 1% decrease in the discount rate would increase the December 31, 2012 retirement plans' projected benefit obligation by 15.7%.
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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):
The following are amounts in accumulated other comprehensive income that are expected to be recognized as components of net periodic benefit cost during 2013 (in thousands):
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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 reviewed at each measurement date. The discount rate used to measure net periodic benefit cost is based on a spot rate yield curve that matches projected future payments with the appropriate interest rate applicable to the timing of the projected future benefit payments.
The Company’s overall expected long-term rate of return on assets is 7.5% effective January 1, 2012, 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 presented below:
The Retirement Plan fund includes a diversified portfolio of 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 a real estate limited partnership. The expected returns for 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 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 mutual funds and 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 real estate limited partnership is reported at the net asset value of the investment.
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The fair value of the Company’s Retirement Plan assets at December 31, 2012 and 2011, 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):
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(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. 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.
The table below reflects the changes in the fair value of investments in real estate during the period (in thousands):
There were no purchases, issuances, and settlements related to the assets in the Level 3 fair value measurement category during the twelve month periods ending December 31, 2012 and 2011.
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
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minimize the risk of owning equity securities by investing in 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 $21.8 million to its retirement plans in 2013.
The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid (in thousands):
Other Postretirement Benefits
The Company provides certain health care benefits for retired employees and their eligible dependents and life insurance benefits for retired employees only. Substantially all of the Company’s employees may become eligible for those benefits if they retire while working for the Company. Contributions from the Company are no more than the IRS tax deductible limit, as actuarially calculated. 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. In March 2010, the President signed into law comprehensive health care reform legislation under the Patient Protection and Affordable Care Act and the Health Care Education and Affordability Reconciliation Act (the "Acts"). The Company modified the operations of the plan to conform to the effective provisions of the Acts.
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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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(a)
These amounts are recognized in the Company’s consolidated balance sheets as a non-current liability.
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:
The discount rate is reviewed at each measurement date. The discount rate used to measure obligations is based on a spot rate yield curve that matches projected future payments with the appropriate interest rate applicable to the timing of the projected future benefit payments. A 1% increase in the discount rate would decrease the December 31, 2012 accumulated postretirement benefit obligation by 14.2%. A 1% decrease in the discount rate would increase the December 31, 2012 accumulated postretirement benefit obligation by 18.1%.
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Net periodic benefit cost is made up of the components listed below (in thousands):
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 2013 is a prior service benefit of $5.6 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 Company reassesses various actuarial assumptions at least on an annual basis. The discount rate is reviewed at each measurement date. The discount rate used to measure net periodic benefit cost is based on a spot yield curve that matches projected future payments with the appropriate interest rate applicable to the timing of the projected future benefit payments.
For measurement purposes, an 8.0% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2012. The rate was assumed to decrease gradually to 4.5% for 2026 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 December 31, 2012 benefit obligation by $23.5 million
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or $18.7 million, respectively. In addition, such a 1% change would increase or decrease the aggregate 2012 service and interest cost components of the net periodic benefit cost by $2.1 million or $1.6 million, respectively.
The Company’s overall expected long-term rate of return on assets, on an after-tax basis, is 5.2% effective January 1, 2012. 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 presented below:
The asset portfolio includes a diversified mix of 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 a real estate limited partnership. The expected returns for 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 postretirement 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 mutual funds and underlying portfolios of the Other Postretirement 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 real estate limited partnership is reported at the net asset value of the investment.
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The fair value of the Company’s Other Postretirement Benefits Plan assets at December 31, 2012 and 2011, 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):
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(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. 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.
The table below reflects the changes in the fair value of the investments in real estate during the period (in thousands):
There were no purchases, issuances, and settlements related to the assets in the Level 3 fair value measurement category during the twelve month periods ending December 31, 2012 and 2011.
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 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.
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The Company expects to contribute $4 million to its other postretirement benefits plan in 2013. 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 2012, 2011 and 2010 were $1.8 million, $1.7 million, and $1.7 million, respectively.
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, regulatory compliance, and customer satisfaction. If a specified level of earnings per share is not attained, no amounts will be paid under the Incentive Plan. In 2012, the Company reached the required levels of earnings per share, safety, regulatory compliance, and customer satisfaction goals for an incentive payment of $7.9 million. The Company reached the required levels of earnings per share, safety, and regulatory compliance goals for an incentive payment of $7.3 million and $7.4 million in 2011 and 2010, respectively. The Company has renewed the Incentive Plan in 2013 with similar goals.
N. Franchises and Significant Customers
El Paso and Las Cruces Franchises
The Company has a franchise agreement with El Paso, the largest city it serves. The franchise agreement allows the Company to utilize public rights-of-way necessary to serve its retail customers within El Paso. The Company is also providing electric distribution service to Las Cruces under an implied franchise by satisfying all obligations under the franchise agreement that expired April 30, 2009.
The franchise arrangements held between the Company and the cities of El Paso and Las Cruces are detailed below:
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(a) Based on a percentage of revenue.
(b) The additional fee of 0.75% is to be placed in a restricted fund to be used solely for economic development and renewable energy purposes.
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 installations represent approximately 5% of annual retail revenues. The Company signed a contract with Fort Bliss in October 2008 under which Fort Bliss takes retail electric service from the Company. The contract with Fort Bliss expired in 2010 and the Company is serving Fort Bliss under the applicable Texas tariffs. In April 1999,
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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.
O. 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, short-term borrowings under the RCF, 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.
Long-Term Debt and Short-Term Borrowings Under the RCF. The fair values of the Company's long-term debt and short-term borrowings under the RCF are based on estimated market prices for similar issues and are presented below (in thousands):
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(1)
Nuclear fuel financing as of December 31, 2012 and December 31, 2011 is funded through the $110 million RGRT Senior Notes and $22.2 million and $13.4 million, respectively under the RCF. As of December 31, 2012, there was no amount outstanding under the RCF for working capital or general corporate purposes. As of December 31, 2011, $20.0 million was outstanding under the RCF for working capital and general corporate purposes. The interest rate on the Company’s borrowings under the RCF is reset throughout the period reflecting 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 2013, approximately $0.4 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, 2012, 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, 2012, the variable, market-based pricing provisions of existing gas contracts are such that these derivative instruments have no significant fair value.
Marketable Securities. The Company’s marketable securities, included in decommissioning trust funds in the balance sheets, are reported at fair value which was $187.1 million and $168.0 million at December 31, 2012 and 2011, respectively. These
EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 (in thousands):
____________________
(1)
Includes approximately 65 securities.
______________________
(2)
Includes approximately 96 securities.
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 recorded 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 2044 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 (in thousands):
EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The Company’s marketable securities include investments in municipal, corporate and federal debt obligations. Substantially all of the Company’s mortgage-backed securities, based on contractual maturity, are due in 10 years or more. The mortgage-backed securities have an estimated weighted average maturity which generally range from 3 years to 7 years and reflects anticipated future prepayments. The contractual year for maturity for these available-for-sale securities as of December 31, 2012 is as follows (in thousands):
The Company recognizes impairment losses on certain of its securities deemed to be other than temporary. In accordance with FASB guidance, these impairment losses are recognized in net income, and a lower cost basis is established for these securities. For the twelve months ended December 31, 2012, 2011, and 2010 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, 2012, 2011, and 2010 and the related effects on pre-tax income are as follows (in thousands):
EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 which are included in deferred charges and other assets on the consolidated balance sheets. 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, mutual funds and U.S. Treasury securities that are in a highly liquid and active market.
•
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 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.
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, 2012 and 2011, 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
Below is a reconciliation of the beginning and ending balance of the fair value of the investment in debt securities (in thousands):
_____________________
(a) These amounts are reflected in the Company's consolidated statement of operations as investment and interest income.
There were no transfers in and out of Level 1 and Level 2 fair value measurements categories during the twelve month periods ending December 31, 2012 and 2011. There were no purchases, issuances, and settlements related to the assets in the Level 3 fair value measurement category during the twelve month periods ending December 31, 2012 and 2011.
P. Supplemental Statements of Cash Flows Disclosures
EL PASO ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Q. Selected Quarterly Financial Data (Unaudited)
The following table summarizes the Company’s unaudited results of operations on a quarterly basis. The quarterly earnings per share amounts for a year will not add to the earnings per share for that year due to the weighting of shares used in calculating per share data.
________________
(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.
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 conducted an evaluation pursuant to Rule 13a-15(b) under the Securities Exchange Act of 1934 of our disclosure controls and procedures as defined in Rule 13a-15(e) under the Securities and Exchange act of 1934. Based on that evaluation, our chief executive officer and our chief financial officer concluded that, as of December 31, 2012, our disclosure controls and procedures are effective.
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 39 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, 2012, 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 2013 Annual Meeting of Shareholders (the “2013 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 2013 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 2013 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 2013 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 2013 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 2013 Proxy Statement under the heading “Summary of Compensation.”
Item 12.
Item 12.
Security Ownership of Certain Beneficial Management
Incorporated herein by reference from the 2013 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 2013 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 2013 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.
*
Filed herewith.
†
Twelve agreements, substantially identical in all material respects to this exhibit, have been entered into with David G. Carpenter; Steven P. Busser; Steven T. Buraczyk; Robert C. Doyle; Nathan T. Hirschi; Mary E. Kipp; Kerry B. Lore; Rocky R. Miracle; Hector R. Puente; Andres R. Ramirez; Henry Wayne Soza; and Guillermo Silva, Jr., officers of the Company.
††
One agreement, dated as of December 4, 2003, identical in all material respects to this Exhibit, has been entered into with Steven P. Busser; officer of the Company.
In lieu of non-employee director cash compensation, twelve agreements, dated as of January 1, 2011, April 1, 2011, and July 1, 2011, 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.
In lieu of non-employee director cash compensation, twelve agreements, dated as of October 1, 2011, substantially identical in all material respects to this Exhibit have been entered into with Catherine A. Allen, Patricia Z. Holland-Branch, and Stephen N. Wertheimer; directors of the Company.
†††
In lieu of non-employee director cash compensation, nine agreements, dated as of January 1, 2012, April 1, 2012 and July 1, 2012, substantially identical in all material respects to this Exhibit, have been entered into with Catherine A. Allen; Patricia Z. Holland-Branch; and Stephen N. Wertheimer directors of the Company.
In lieu of non-employee director cash compensation, four agreements, dated as of October 1, 2012, substantially identical in all material respects to this Exhibit have been entered into with Catherine A. Allen, Patricia Z. Holland-Branch, Michael K. Parks; and Stephen N. Wertheimer; directors of the Company.
In lieu of non-employee director cash compensation, eleven agreements, dated as of May 26, 2011, substantially identical in all material respects to this Exhibit, were entered into with Catherine A. Allen; J. Robert Brown; James W. Cicconi; James W. Harris; Kenneth R. Heitz; Patricia Z. Holland-Branch; Michael K. Parks; Thomas V. Shockley, III; Eric B. Siegel; Stephen N. Wertheimer; and Charles A. Yamarone; directors of the Company.
In lieu of non-employee director cash compensation, ten agreements, dated as of May 31, 2012, substantially identical in all material respects to this Exhibit, were entered into with Catherine A. Allen; J. Robert Brown; James W. Cicconi; 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.
††††
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 Thomas V. Shockley III, David G. Carpenter and Mary E. Kipp, 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 25th day of February 2013.
EL PASO ELECTRIC COMPANY
By:
/s/ THOMAS V. SHOCKLEY III
Thomas V. Shockley III
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.