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 several electrical generating facilities providing it with a net dependable generating capacity of approximately 2,085 megawatts ("MW"). For the year ended December 31, 2018, the Company’s energy sources consisted of approximately 44% nuclear fuel, 44% natural gas, 12% purchased power and less than 1% generated by Company-owned solar photovoltaic panels. As of December 31, 2018, the Company had power purchase agreements for 107 MW from solar photovoltaic generation facilities and intends to expand its portfolio of renewable energy sources, particularly solar photovoltaic generation. See "Energy Sources - Purchased Power."
The Company serves approximately 425,000 residential, commercial, industrial, public authority and wholesale customers. The Company distributes electricity to retail customers principally in El Paso, Texas and Las Cruces, New Mexico (representing approximately 64% and 11%, respectively, of the Company’s retail revenues for the year ended December 31, 2018). 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 U.S. military installations, such as Fort Bliss in Texas and White Sands Missile Range ("White Sands") and Holloman Air Force Base ("HAFB") in New Mexico, an oil refinery, several medical centers, two large universities and a steel production facility.
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, 2019, the Company had approximately 1,100 employees, 37% 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, proxy statement and all amendments to those reports as soon as reasonably practicable after such material is electronically filed with or furnished to the U.S. Securities and Exchange Commission ("SEC"). In addition, copies of this Annual Report on Form 10-K 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 Company's website is not incorporated by reference into this Annual Report on Form 10-K.
Facilities
As of December 31, 2018, the Company’s net dependable generating capability of approximately 2,085 MW consists of the following:
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* During summer peak period.
** Renewable nameplates are 8 MW with 70% contribution at time of peak.
Palo Verde
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 Arizona Nuclear Power Project Participation Agreement dated August 23, 1973, as amended ("ANPP Participation Agreement"), the Company has limited ability to influence operations and costs at Palo Verde.
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Palo Verde Operating Licenses. Operation of each of the three Palo Verde Units requires an operating license from the U.S. Nuclear Regulatory Commission ("NRC"). The NRC issued full power operating licenses for Unit 1 in June 1985, Unit 2 in April 1986 and Unit 3 in November 1987 and issued renewed operating licenses for each of the three units in April 2011, which extended the licenses for Units 1, 2 and 3 to June 2045, April 2046 and November 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 2017, the Palo Verde Participants approved the 2016 Palo Verde decommissioning study ("2016 Study"), which estimated that the Company must fund approximately $432.8 million (stated in 2016 dollars) to cover its share of decommissioning costs. At December 31, 2018, the Company's decommissioning trust fund had a balance of $276.9 million. Although the 2016 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 and Waste Disposal. Pursuant to the Nuclear Waste Policy Act of 1982, as amended in 1987, the U.S. Department of Energy ("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 by 1998. The DOE's obligations are reflected in a contract for Disposal of Spent Nuclear Fuel and/or High-Level Radioactive Waste ("Standard Contract") with each nuclear power plant. The DOE failed to begin accepting spent nuclear fuel by 1998. On December 19, 2012, APS, acting on behalf of itself and the Palo Verde Participants, filed a second breach of contract lawsuit against the DOE. This lawsuit sought to recover damages incurred due to the DOE’s failure to accept Palo Verde’s spent nuclear fuel for the period beginning January 1, 2007 through June 30, 2011. Pursuant to the terms of the August 18, 2014 settlement agreement, and as amended with the DOE, APS files annual claims for the period July 1 of the then-previous year to June 30 of the then-current year on behalf of itself and those utilities that share in power and energy entitlements, and bear certain allocated costs, with respect to Palo Verde based upon the ANPP Participation Agreement dated August 23, 1973. The settlement agreement, as amended, provides APS with a method for submitting claims and receiving recovery for costs incurred through December 31, 2016, which has been extended to December 31, 2019. The Company's share of costs recovered in 2018, 2017, and 2016, respectively are presented below (in thousands):
On October 31, 2018, APS filed a $10.2 million claim for the period July 1, 2017 through June 30, 2018. The Company's share of this claim is approximately $1.6 million. This claim is pending DOE review. The majority of the reimbursement received by the Company is expected to be credited to customers through the applicable fuel adjustment clauses.
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DOE’s Construction Authorization Application for Yucca Mountain. The DOE had planned to meet its disposal obligations by designing, licensing, constructing and operating a permanent geologic repository in Yucca Mountain, Nevada. In March 2010, the DOE filed a motion to dismiss with prejudice its Yucca Mountain construction authorization application that was pending before the NRC. Several interested parties have intervened in the NRC proceeding. 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 and NRC’s cessation of its review of the Yucca Mountain construction authorization application. The cases have been consolidated into one matter at the U.S. Court of Appeals for the
District of Columbia Circuit ("D.C. Circuit"). In August 2013, the D.C. Circuit ordered the NRC to resume its review of the application with available appropriated funds.
On October 16, 2014, the NRC issued Volume 3 of the safety evaluation report developed as part of the Yucca Mountain construction authorization application. This volume addresses repository safety after permanent closure, and the issuance of Volume 3 is a key milestone in the Yucca Mountain licensing process. Volume 3 contains the NRC staff’s finding that the DOE’s repository design meets the requirements that apply after the repository is permanently closed, including but not limited to the post-closure performance objectives in the NRC’s regulations.
On December 18, 2014, the NRC issued Volume 4 of the safety evaluation report developed as part of the Yucca Mountain construction authorization application. This volume covers administrative and programmatic requirements for the repository. It documents the NRC staff’s evaluation of whether the DOE’s research and development and performance confirmation programs, as well as other administrative controls and systems, meet applicable NRC requirements. Volume 4 contains the NRC staff’s finding that most administrative and programmatic requirements in NRC regulations are met, except for certain requirements relating to ownership of land and water rights.
Publication of Volumes 3 and 4 does not signal whether or when the NRC might authorize construction of the repository. The Company cannot predict when spent fuel shipments to the DOE will commence.
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Waste Confidence and Continued Storage. On June 8, 2012, the D.C. Circuit issued its decision on a challenge by several states and environmental groups of the NRC’s rulemaking regarding temporary storage and permanent disposal of high level nuclear waste and spent nuclear fuel. The petitioners challenged the NRC’s 2010 update to the agency’s Waste Confidence Decision and temporary storage rule ("Waste Confidence Decision").
The D.C. Circuit found that the agency’s 2010 Waste Confidence Decision update constituted a major federal action, which, consistent with the National Environmental Policy Act ("NEPA"), requires either an environmental impact statement or a finding of no significant impact from the agency’s actions. The D.C. Circuit found that the NRC’s evaluation of the environmental risks from spent nuclear fuel was deficient, and therefore remanded the 2010 Waste Confidence Decision update for further action consistent with NEPA.
On September 6, 2012, the NRC Commissioners issued a directive to the NRC staff to proceed directly with development of a generic environmental impact statement to support an updated Waste Confidence Decision. The NRC Commissioners also directed the NRC staff to establish a schedule to publish a final rule and environmental impact study within 24 months of September 6, 2012.
In September 2013, the NRC issued its draft Generic Environmental Impact Statement ("GEIS") to support an updated Waste Confidence Decision. On August 26, 2014, the NRC approved a final rule on the environmental effects of continued storage of spent nuclear fuel. Renamed the Continued Storage Rule, the NRC's decision adopted the findings of the GEIS regarding the environmental impacts of storing spent fuel at any reactor site after the reactor’s licensed period of operations. As a result, those generic impacts do not need to be re-analyzed in the environmental reviews for individual licenses. Although Palo Verde has not been involved in any licensing actions affected by the D.C. Circuit’s June 8, 2012 decision, the NRC lifted its suspension on final licensing actions on all nuclear power plant licenses and renewals that went into effect when the D.C. Circuit issued its June 2012 decision. The final Continued Storage Rule was subject to continuing legal challenges before the NRC and the Court of Appeals. In June 2016, the D.C. Circuit issued its final decision, rejecting all remaining legal challenges to the Continue Storage Rule. On August 8, 2016, the D.C. Circuit denied a petition for rehearing.
Palo Verde has sufficient capacity at its on-site independent spent fuel storage installation ("ISFSI") to store all of the nuclear fuel that will be irradiated during the initial operating license period, which ends in December 2027. Additionally, Palo Verde has sufficient capacity at its on-site ISFSI to store a portion of the fuel that will be irradiated during the period of extended operation, which ends in November 2047. If uncertainties regarding the U.S. government’s obligation to accept and store spent fuel are not favorably resolved, APS will evaluate alternative storage solutions that may obviate the need to expand the ISFSI to accommodate all of the fuel that will be irradiated during the period of extended operation.
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The One-Mill Fee. In 2011, the National Association of Regulatory Utility Commissioners and the Nuclear Energy Institute challenged the DOE’s 2010 determination of the adequacy of the one tenth of a cent per kilowatt-hour ("kWh") fee ("one-mill fee") paid by the nation’s commercial nuclear power plant owners pursuant to their individual obligations under the Standard Contract. This fee was recovered by the Company through applicable
fuel adjustment clauses. In June 2012, the D.C. Circuit held that the DOE failed to conduct a sufficient fee analysis in making the 2010 determination. The D.C. Circuit remanded the 2010 determination to the Secretary of the DOE with instructions to conduct a new fee adequacy determination within six months. In February 2013, upon completion of the DOE’s revised one-mill fee adequacy determination, the court reopened the proceedings. On November 19, 2013, the D.C. Circuit ordered the Secretary of the DOE to notify Congress of his intent to suspend collecting annual fees for nuclear waste disposal from nuclear power plant operators, as he is required to do pursuant to the NWPA and the court’s order. On January 3, 2014, the Secretary of the DOE notified Congress of his intention to suspend collection of the one-mill fee, subject to Congress’ disapproval and on May 16, 2014, the DOE notified all commercial nuclear power plant operators, effective May 16, 2014, the one-mill fee was suspended. Electricity generated at Palo Verde and sold on or after May 16, 2014 is no longer subjected to the one-mill fee.
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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 U.S., 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, the NRC established a task force to conduct a systematic and methodical review of NRC processes and regulations to determine whether the agency should make additional improvements to its regulatory system. On March 12, 2012, the NRC issued the first regulatory requirements based on the recommendations of the NRC's Near Term Task Force. 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 issued a series of interim staff guidance documents regarding implementation of these requirements. Palo Verde has met the NRC's imposed deadlines for the installation of equipment to address these requirements. Palo Verde has spent approximately $125.4 million (the Company's share is $19.8 million) on capital enhancements related to these requirements as of December 31, 2018.
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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 $62.1 million, with an annual payment limitation of approximately $9.7 million. The Palo Verde Participants also maintain $2.8 billion of "all risk" nuclear property insurance. The insurance provides coverage for property damage and decontamination at Palo Verde. For covered incidents involving property damage not accompanied by a release of radioactive material, the policy's coverage limit is $2.3 billion. 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 Company owns the Newman Power Station ("Newman"), which consists of three conventional steam-electric generating units and two combined cycle generating units. The station operates primarily on natural gas but the conventional steam-electric generating units can also operate on fuel oil.
The Company owns the Rio Grande Power Station ("Rio Grande"), which consists of two conventional steam-electric generating units and one aeroderivative unit that operates on natural gas. Rio Grande Unit 6 with net capacity of 42.5 MW, was initially placed in inactive reserve status in 2015, and has been activated as needed.
The Company owns the Montana Power Station ("MPS"), which consists of four aeroderivative generating units that operate on natural gas. The units can also operate on fuel oil.
The Company owns the Copper Power Station ("Copper"), which consists of a natural gas combustion turbine used primarily to meet peak demand.
Prior to July 6, 2016, the Company owned a 7% interest in Units 4 and 5 at Four Corners Generating Station ("Four Corners"). The Company shared power entitlements and certain allocated costs of the two units with APS (the Four Corners operating agent) and the other Four Corners participants. On July 6, 2016, the Company sold its interests in Four Corners for $32.0 million to 4C Acquisition, LLC, an affiliate of APS ("APS's affiliate"), and Pinnacle West Capital Corporation ("Pinnacle West"), the parent company of APS and APS's affiliate. No significant gain or loss was recorded for this sale. APS's affiliate assumed responsibility
for all Four Corners capital expenditures made after July 6, 2016, which assumption is guaranteed by Pinnacle West. In addition, APS's affiliate will indemnify the Company against certain liabilities and costs related to the future operation of Four Corners, which indemnification is guaranteed by Pinnacle West. See Part II, Item 8, Financial Statements and Supplementary Data, Note D and Note F of Notes to Financial Statements for further discussions.
Solar Photovoltaic Facilities
The Company’s Texas Community solar facility, a 3 MW utility-scale solar plant located at MPS, and the El Paso Electric Holloman Atlas Solar Array, a 5 MW utility-scale solar plant located on HAFB, began commercial operations on May 31, 2017, and October 18, 2018, respectively. The Company also owns six other solar photovoltaic facilities with a total capacity of 0.2 MW.
Transmission and Distribution Lines and Agreements
The Company owns, or has significant ownership interests in, four 345 kilovolt ("kV") transmission lines in New Mexico and Arizona and three 500 kV lines in Arizona. These lines enable the Company to deliver its energy entitlements from its remote generation at Palo Verde to its service area (pursuant to various transmission and power exchange agreements to which the Company is a party). The Company also 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. 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 Tucson Electric Power Company's ("TEP") Springerville Generating Plant near Springerville, Arizona, to the Company's Diablo Substation near Sunland Park, New Mexico.
(2)
Runs from Public Service Company of New Mexico's ("PNM") West Mesa Substation near Albuquerque, New Mexico, to the Company's Arroyo Substation near Las Cruces, New Mexico.
(3)
Runs from TEP's Greenlee Substation near Duncan, Arizona to Newman.
(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 near Gila Bend, Arizona, then to the Kyrene Substation near Tempe, Arizona.
Environmental Matters
General. The Company is subject to extensive laws, regulations and permit requirements with respect to air and GHG emissions, water discharges, 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.
In March 2017, the Company entered into a Compliance Agreement ("Compliance Agreement") with the Texas Commission on Environmental Quality under the Texas Environmental, Health and Safety Audit Privilege Act to address certain water and waste compliance issues associated with the integrity of the synthetic liner of the evaporation pond at Newman. The Company has initiated a capital project to extend the life of evaporation pond and in doing so will complete its obligation of the Compliance Agreement. The Compliance Agreement remains in effect.
Air Emissions. The U.S. Clean Air Act ("CAA"), associated regulations and comparable state and local laws and regulations relating to air emissions impose, among other obligations, limitations on pollutants generated during the operations of the Company's facilities and assets, including sulfur dioxide, particulate matter and nitrogen oxides.
National Ambient Air Quality Standards ("NAAQS"). Under the CAA, the U.S Environmental Protection Agency ("EPA") sets NAAQS for six criteria pollutants considered harmful to public health and the environment, including particulate matter, nitrogen oxide, carbon monoxide, ozone and sulfur dioxide. On October 1, 2015, the EPA released a final rule tightening the primary and secondary NAAQS for ground-level ozone from its 2008 standard levels of 75 parts per billion ("ppb") to 70 ppb. The EPA published the Final Rule on June 4, 2018, designating El Paso County, Texas, as "attainment/unclassifiable" under the 2015 ozone NAAQS and designating a section of southern Doña Ana County, New Mexico, as "nonattainment." In August, several petitions for review of the Final Rule were filed in the D.C. Circuit. One of these petitions, filed by the City of Sunland Park, New Mexico, specifically challenges the "attainment/unclassifiable" designation of El Paso County, Texas. The Company and other intervenors filed and were granted motions to intervene in the challenges to EPA's 2015 ozone NAAQS designations. A briefing schedule extending through July 2019 has been established for the case.
States, including New Mexico, that contain any areas designated as nonattainment are required to complete development of implementation plans in the 2020-2021 timeframe. Most nonattainment areas are expected to have until 2020 or 2023 to meet the primary (health) standard, with the exact attainment date varying based on the ozone level in the area. 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 NAAQS, individually or in the aggregate, could have a material impact on its operations and financial results.
Other Laws and Regulations and Risks. The Company sold its interest in Four Corners to APS's affiliate on July 6, 2016 at the expiration of the 50-year participation agreement. As of the closing date of the sale, the Company’s environmental liabilities associated with Four Corners were limited to conditions that existed at the time of the sale and further limited to the portion thereof for which the Company would have been financially responsible if Four Corners had fully ceased operation on July 6, 2016. Pursuant to the terms of the asset purchase agreement ("Purchase and Sale Agreement"), neither APS's affiliate nor APS assumed the Company's pre-closing obligations under environmental laws with respect to its interest in Four Corners. The Company may be subject to certain future claims under environmental laws and regulations as a former owner of Four Corners. The extent of such claims, if any, cannot be predicted with certainty.
Climate Change. There has been a wide-ranging policy debate, at the local, state, national and international levels, regarding the impact of GHG and possible means for their regulation. Efforts continue to be made in the international community toward the adoption of international treaties or protocols that would address global climate change issues. In April 2016, the United States signed the Paris Agreement, which requires countries to review and "represent a progression" in their intended nationally determined contributions, which set GHG emission reduction goals, every five years beginning in 2020. In August 2017, the United States formally documented to the United Nations its intent to withdraw from the Paris Agreement. The earliest possible effective withdrawal date from the Paris Agreement is November 2020. At the state level, several states have already adopted measures requiring GHG emissions to be reduced within state boundaries. For example, the governor of New Mexico signed an executive order in January 2019 that supports the Paris Agreement and includes a goal of reducing statewide GHG emissions by at least 45% by 2030. The executive order also creates a Climate Change Task Force to evaluate and develop regulatory strategies to reach the 45% reduction goal. Although the Company cannot currently determine the effect of potential regulatory strategies that may be
suggested by the New Mexico Climate Change Task Force, if implemented, they could be material to the Company's business, reputation, financial condition or results of operations.
The federal government has considered, proposed and/or finalized legislation or regulations limiting GHG emissions, including carbon dioxide. In particular, the U.S. Congress has considered legislation to restrict or regulate GHG emissions. In October 2015, the EPA published a rule establishing guidelines for states to regulate carbon dioxide emissions from existing power plants, known as the Clean Power Plan ("CPP"). Legal challenges to the CPP are ongoing. On August 31, 2018, the EPA published a proposal to replace the CPP called the Affordable Clean Energy ("ACE") rule. The ACE rule has not yet been finalized. At this time the Company cannot determine the impact that the CPP, the ACE rule, and related proposals and legal challenges may have on our financial position, results of operations or cash flows.
A significant portion of the Company's generation assets are nuclear or gas-fired, and as a result, the Company believes that its GHG emissions are low relative to electric power companies who rely more on coal-fired generation. Current and future legislation and regulation of GHG or any future related litigation could impose significant costs and/or operating restrictions on the Company, reduce demand for the power the Company generates, and/or require the Company to purchase rights to emit GHG, any of which could be material to the Company's business, reputation, financial condition or results of operations.
Climate change also has potential physical effects that could be relevant to the Company's business. 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 significant 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 not possible to meaningfully quantify the costs of these potential impacts at present.
Environmental Litigation and Investigations. Since July 2011, the U.S. Department of Justice, on behalf of the EPA, and APS have been engaged in substantive settlement negotiations in an effort to resolve certain 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 sulfur dioxide, nitrogen oxides, and particulate matter, and that APS failed to obtain an operating permit under Title V of the CAA that reflects applicable requirements imposed by law. On June 24, 2015, the parties filed with the U.S. District Court for the District of New Mexico a settlement agreement ("CAA Settlement Agreement") resolving this matter. On August 17, 2015, the U.S. District Court entered the CAA Settlement Agreement. The agreement imposes a total civil penalty payable by the co-owners of Four Corners collectively in the amount of $1.5 million, and it requires the co-owners to pay $6.7 million for environmental mitigation projects. At December 31, 2018, the Company has accrued its remaining unpaid share of approximately $0.2 million related to this matter.
Construction Program
Utility construction expenditures reflected in the following table consist primarily of local generation, expanding and updating the transmission and distribution systems, the cost of capital improvements and replacements at Palo Verde and other generating facilities, and other property and equipment. Studies indicate that the Company will need additional power generation resources to meet increasing load requirements on its system and to replace retiring plants. After evaluation of the competitive 2017 All Source Request for Proposals for Electric Power Supply and Load Management Resources (“2017 All Source RFP”), the winning bids include the construction of a 226 MW natural gas combustion turbine generating unit at Newman in El Paso with an anticipated operational date in 2023. The costs of the new generating unit are included in the table below. The winning bids also included purchased power agreements for 200 MW of utility scale solar resources and 100 MW of battery storage, which are not included in the construction program. The selected proposals are subject to the execution of contracts following negotiations with the winning bidders, obtaining the applicable environmental and construction related permits, and obtaining necessary approvals by the Public Utility Commission of Texas ("PUCT") and the New Mexico Public Regulation Commission ("NMPRC").
The Company’s estimated cash construction costs for 2019 through 2023 are approximately $1.3 billion. Actual costs may vary from the construction program estimates shown. Such estimates are under continuous review and subject to ongoing adjustment and are 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)
Estimated production costs consist of:
a.
$185 million for new generating capacity, including:
i.
$143 million of construction costs from 2019 through 2023 for a 226 MW combustion turbine generating unit at Newman with an anticipated operational date in 2023 as a result of the 2017 All Source RFP.
ii.
$42 million of initial construction costs from 2019 through 2023 for a 320 MW combined cycle generating unit to be completed in 2027.
b.
$265 million of other generation costs, including $185 million for Palo Verde.
(3)
Estimated distribution costs include:
a.
$85 million of initial project costs for Advanced Metering Infrastructure ("AMI"), including deployment of the back-office systems and meters. Legislative proposals regarding the clarification of the regulatory process to implement AMI are anticipated during the Texas legislative session that convened in January 2019. With legislative clarification, the Company would then have the opportunity to request regulatory approval for the deployment of AMI.
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 Company-owned solar photovoltaic panels and wind turbines accounted for less than 1% of the total kWh energy mix of the Company.
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 Part II, Item 8, Financial Statements and Supplementary Data, Note D of Notes to Financial Statements for further discussion on Texas 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 2025 and 15% of its requirements through 2028. The participants have contracted for 100% of Palo Verde's requirement for conversion services through 2025 and 40% of its requirements through 2028. The participants have also contracted for 100% of Palo Verde's requirement for enrichment services through 2021 and 90% of its requirement for 2022, and 80% for 2023 through 2026 and all of Palo Verde's requirement for fuel assembly fabrication services through 2027.
Nuclear Fuel Financing. The Company’s financing of nuclear fuel is accomplished through Rio Grande Resources Trust II ("RGRT"), a Texas grantor trust, which is consolidated in the Company’s financial statements. As of December 31, 2018, RGRT has $110 million aggregate principal amount of senior notes due 2020 and 2025. On June 28, 2018, RGRT completed the sale of $65 million aggregate principal amount of senior notes due August 15, 2025. The Company guarantees the payment of principal and interest on the RGRT senior notes. The proceeds from the sale of the RGRT senior notes were used by RGRT to repay amounts borrowed under the then-existing revolving credit facility and enable future nuclear fuel financing requirements of RGRT to be met with a combination of the senior notes and amounts borrowed under the Company's Revolving Credit Facility ("RCF").
Natural Gas
The Company manages its natural gas requirements through a combination of a long-term (greater than a year) supply contract, several medium-term (greater than a month but less than one year) supply contracts and spot or short-term (daily to a month) market purchases. The long-term supply contract provides for firm deliveries of gas at market-based index prices. Medium-term and spot agreements are either fixed priced and/or index priced depending on the market. Through March 2018, the Company’s natural gas requirements at Newman, Rio Grande and MPS were met with short-term, medium-term and long-term natural gas purchases from various suppliers; thereafter, there were only short-term and medium term natural gas purchases, and this practice is expected to continue in 2019. Interstate gas is delivered under a base firm transportation contract. The Company has expanded its firm interstate transportation contract to include MPS. 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 Newman, Rio Grande and MPS. The Company will continue to evaluate the availability of short-term natural gas supplies versus medium and long-term supplies to maintain a reliable and economical supply for its local generating stations.
Natural gas for Newman and Copper was also delivered pursuant to a long-term intrastate natural gas contract for firm transportation that became effective October 1, 2009 and continued through March 31, 2018. Beginning April 1, 2018, intrastate natural gas reservation and storage for Newman and Copper has been provided through new contracts with ONEOK WesTex Transmission, LLC and ONEOK Texas Gas Storage, LLC, respectively, that continue through March 31, 2028. It is anticipated that deliveries of intrastate natural gas to MPS may begin in the first quarter of 2019. Under this new contract, intrastate gas supply will be sourced in the same manner as interstate gas through a variety of medium and short-term purchase contracts.
Purchased Power
To supplement its own generation and operating reserve requirements, and to meet its Renewable Portfolio Standard ("RPS") requirements, the Company engages in power purchase arrangements that may vary in duration and amount based on an evaluation of the Company’s resource needs, the economics of the transactions and specific RPS requirements.
The Company has a firm 100 MW Power Purchase and Sale Agreement ("Power Purchase and Sale Agreement") with Freeport-McMoran Copper and Gold Energy Services LLC ("Freeport"), pursuant to which Freeport will deliver energy to the Company from the Luna Energy Facility (a natural gas-fired combined cycle generation facility located in Luna County, New Mexico) and the Company will deliver a like amount of energy at Greenlee, Arizona. The Company may purchase up to the contracted MW amount at a specified price at times when energy is not exchanged under the Power Purchase and Sale Agreement. The Power Purchase and Sale Agreement was approved by the Federal Energy Regulatory Commission ("FERC") and will continue through an initial term ending December 31, 2021, with subsequent rollovers until terminated. Upon mutual agreement, the Power Purchase and Sale Agreement allows the parties to increase the amount of energy that is purchased and sold thereunder. The parties have agreed to increase the amount up to 125 MW through December 2021.
The Company has entered into several power purchase agreements to help meet its RPS requirements. Specifically, the Company has a 25-year power purchase 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. In June 2015, the Company entered into a consent agreement with Hatch Solar Energy Center I, LLC to provide for additional or replacement photovoltaic modules. The Company also entered into a 20-year contract with Solar Roadrunner, LLC, a subsidiary of Global Infrastructure Partners, (formerly known as NRG Solar Roadrunner LLC) 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. In addition, the Company has 25-year power purchase agreements to purchase all of the output of two additional solar photovoltaic projects located in southern New Mexico, SunE EPE1, LLC (10 MW) and SunE EPE2, LLC (12 MW), which began commercial operation in June 2012 and May 2012, respectively. In September 2017, Longroad Solar Portfolio Holdings, LLC purchased SunE EPE1, LLC, and in October 2017, Silicon Ranch Corporation purchased SunE EPE2, LLC with the Company's consent per the terms of both power purchase agreements.
Furthermore, the Company has a 20-year power purchase agreement with Macho Springs Solar, LLC to purchase the entire generation output delivered from the 50 MW Macho Springs solar photovoltaic project located in Luna County, New Mexico which began commercial operation in May 2014. Finally, the Company has a 30-year power purchase agreement with Newman Solar LLC to purchase the total output, which is approximately 10 MW, from a solar photovoltaic generation plant on land subleased from the Company in proximity to Newman. This solar project began commercial operation in December 2014.
Other purchases of shorter duration were made during 2018 to supplement the Company's generation resources during planned and unplanned outages, for economic reasons and to supply off-system sales.
The Company recently concluded and announced its selection of resources from its 2017 All Source RFP. In addition to conventional natural gas generation, the Company will be initiating contract negotiations during 2019 for power purchase agreements from both solar and battery storage resources. Furthermore, the Company will pursue negotiations for possible additional solar and wind purchase power if there are potential energy cost savings.
Operating Statistics
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(1)
The number of retail customers presented is based on the number of service locations.
(2)
Includes spot sales and net losses of 77,000 kilowatts ("kW"), 47,000 kW and 135,000 kW for 2018, 2017 and 2016, respectively.
Regulation
General
The rates and services of the Company are regulated by incorporated municipalities in Texas, the PUCT, the NMPRC and the FERC. Municipal orders, ordinances and other agreements regarding rates and services adopted by Texas municipalities are subject to review and approval by the PUCT. The FERC has jurisdiction over the Company's wholesale (sales for resale - full requirement customer) transactions, transmission service and compliance with federally-mandated reliability standards. The decisions of the PUCT, the NMPRC and the FERC are subject to judicial review. See Part II, Item 8, Financial Statements and Supplementary Data, Note D of Notes to Financial Statements for further discussion on Regulatory Matters.
Power Sales Contracts
The Company has entered into several short-term (three months or less) off-system sales contracts throughout 2018.
Franchises and Significant Customers
Franchises
The Company operates under franchise agreements with several cities in its service territory, including one with El Paso, Texas, the largest city it serves. The franchise agreement allows the Company to utilize public rights-of-way necessary to serve its customers within El Paso. Pursuant to the El Paso franchise agreement, the Company pays to the City of El Paso, on a quarterly basis, a fee equal to 5.00% of gross revenues the Company receives for the generation, transmission and distribution of electrical energy and other services within the city. The 2005 El Paso franchise agreement set the franchise fee at 3.25% of gross revenues, but that amount has since been adjusted by two amendments. The 2010 amendment added an incremental fee equal to 0.75% of gross revenues to be placed in a restricted fund to be used by the city solely for economic development and renewable energy purposes. The 2018 amendment, approved on March 20, 2018, and applicable to bills issued on or after October 1, 2018, increased the dedicated incremental fee by 1.00% of gross revenues and extended the term of the franchise agreement by 30 years. Any assignment of the franchise agreement, including a deemed assignment as a result of a change in control of the Company, requires the consent of the City of El Paso. The El Paso franchise agreement is set to expire on July 31, 2060.
The Company does not have a written franchise agreement with Las Cruces, New Mexico, the second largest city in its service territory. The Company utilizes public rights-of-way necessary to service its customers within Las Cruces under an implied franchise pursuant to state law by satisfying all obligations under the franchise agreement that expired on April 30, 2009. The Company pays the City of Las Cruces a franchise fee of 2.00% of gross revenues the Company receives from services within the City of Las Cruces.
The Company also maintains franchise agreements with other municipalities, and applicable counties, within its service territories.
Military Installations
The Company serves HAFB, White Sands and Fort Bliss. These military installations represent approximately 2.6% of the Company's annual retail revenues. In July 2014, the Company signed an agreement with Fort Bliss under which Fort Bliss takes retail electric service from the Company under the applicable Texas tariffs. The Company serves White Sands under the applicable New Mexico tariffs. In August 2016, the Company signed a contract with HAFB under which the Company provides retail electric service and limited wheeling services to HAFB under the applicable New Mexico tariffs. As stated in the contract, HAFB will purchase the full output of a Company-owned 5 MW solar facility upon its completed construction, which occurred on October 18, 2018. HAFB's other power requirements are provided under the applicable New Mexico tariffs with limited wheeling services under the contract.
Other Information
Investors should note that we announce material financial information in our filings with the SEC, press releases and public conference calls. Based on guidance from the SEC, we may also use the Investor Relations section of our website (www.epelectric.com) to communicate with investors about the Company. It is possible that the financial information we post there could be deemed to be material information. The information contained on or accessible from our website is not incorporated by reference into and does not constitute a part of this Annual Report on Form 10-K.
Item 1A.
Item 1A.
Risk Factors
Like other companies in our industry, our financial results are 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 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 Annual Report on Form 10-K and in our other filings with the SEC.
Our Revenues and Profitability Depend Upon Regulated Rates
Our rates are governed by Texas, New Mexico and federal laws and regulations, with our retail rates subject to regulation by incorporated municipalities in Texas, the PUCT, the NMPRC and our wholesale rates subject to regulation by the FERC. There can be no assurance that the laws and regulations or the application thereof in our different jurisdictions will be similar or consistent, which could lead to different treatment of certain matters by our regulators in different jurisdictions. The PUCT Final Order in Docket No. 46831 ("2017 PUCT Final Order") established our current retail base rates in Texas, effective July 18, 2017. In addition, the NMPRC Final Order in Case No. 15-00127-UT ("NMPRC Final Order") established rates in New Mexico that became effective in July 2016.
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, New Mexico rate cases, or FERC rate cases will result in rates that will allow us to fully recover our costs including a reasonable return on invested capital, or that our regulators will make similar or consistent determinations with respect to our rates, operations or other matters before our regulators. There can be no assurance that regulators will determine that all of our costs are reasonable and have been prudently incurred including costs associated with future plant retirements. It is also likely that third parties will intervene in any cases and challenge whether our costs are reasonable and necessary. If all of our costs are not recovered, or timely recovered, through the retail 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 and Transmission Assets
We received approval, both from the PUCT and the NMPRC, to construct Units 3 and 4, two 89 MW simple-cycle aeroderivative combustion turbines at MPS. In 2016, we completed construction of these units, which began commercial operation in May 2016 and September 2016, respectively. The PUCT approved the inclusion of the Texas jurisdictional portion of MPS Units 3 and 4 in base rates in the 2017 PUCT Final Order. However, the New Mexico jurisdiction portion of MPS Units 3 and 4 have not yet been approved by the NMPRC for inclusion in customer base rates. Accordingly, we are exposed to the risk of failing to recover these costs as well as costs associated with the construction of other new units and transmission and distribution assets.
We announced the results of the 2017 All Source RFP on December 26, 2018, that includes a diverse generation mix. The selected proposals are subject to the execution of contracts following negotiations with the winning bidders, obtaining the applicable environmental and construction related permits and obtaining necessary approvals by the PUCT and the NMPRC.
In addition, for all resource additions, if the contracts, permits, approvals, or the construction of the new unit is not completed on time, we may be required to purchase power or operate less efficient generating units to meet customer requirements. Any replacement purchased power or fuel costs will be subject to regulatory review by the PUCT and the 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.
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
The global credit and equity markets and the overall economy can be extremely volatile which could have a number of adverse effects on our operations, funding obligations and 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 stock market performance may reduce the value of our financial assets and decommissioning trust investments and negatively impact our results of operations. Similarly, inflationary increases will increase our future decommission obligations. Such market results may also increase our funding obligations for our pension plans, other post-retirement benefit plans and the NDT. Changes in the corporate interest rates that 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, an economic downturn may result in reduced customer demand, both in the retail and wholesale markets, and increases in customer delinquencies and write-offs. Uncertainty in the credit markets may negatively impact the ability of our customers to finance purchases of our services and could adversely affect the collectability of our receivables. The credit markets and overall economy (including inflationary increases) may also adversely impact our ability to arrange future financings on acceptable terms and therefore our ability to refinance our existing indebtedness could be limited. Furthermore, 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.
Similarly, actions or inaction of Congress and of governmental agencies can impact our operations. Partial government shutdowns, such as occurred in 2013 and the end of 2018 and the beginning of 2019, can impact both sales and timely receivables from public authorities, commercial, industrial and residential customers. The occurrence of any of these events could have a material adverse effect on our results of operations, financial condition and cash flows.
There are Inherent Risks in the Ownership of Nuclear Facilities
Our 15.8% ownership interest in Palo Verde, which is the largest nuclear electric generating facility in the U.S., subjects us to a number of risks. A significant percentage of our generating capacity, off-system sales margins, assets and operating expenses is attributable to Palo Verde. Our interest in each of the three Palo Verde units totals approximately 633 MW of generating capacity. Palo Verde represents approximately 30% of our available net generating capacity and provided approximately 44% of our energy requirements for the twelve months ended December 31, 2018. Palo Verde comprises approximately 24% of our total net plant-in-service and Palo Verde expenses comprise a significant portion of O&M 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 90.2% and 93.8% in the twelve months ended December 31, 2018 and 2017, respectively.
We participate in Palo Verde with one or more parties who may not have the same goals, strategies, priorities or resources as we do and may compete with us. Furthermore, regulatory compliance issues and financial restraints could cause these parties to make decisions that could potentially be adverse to us. Additionally, if one or more of the participants defaults in performance of its obligations under the ANPP Participation Agreement, the non-defaulting participants must bear all operating, maintenance, and other costs otherwise payable by the defaulting participant (and will receive the generation share of the defaulting participant) in the ratio of their respective share to the total shares of all non-defaulting participants.
As Palo Verde is a nuclear electric generating facility, it is subject to environmental, health and financial risks, such as the ability to obtain adequate supplies of nuclear fuel and water; the ability to dispose of spent nuclear fuel; increases in decommissioning costs due to inflation and regulatory changes, the ability to maintain adequate trust fund reserves for decommissioning; potential liabilities arising out of the operation of these facilities; the costs of securing the facilities against possible terrorist attacks; cyber attacks, or other causes; and unscheduled outages due to equipment and other problems. If a nuclear incident were to occur at Palo Verde, it could materially and adversely affect our results of operations and financial condition. A major incident at a nuclear facility anywhere in the world could cause regulatory bodies to limit or prohibit the operation or licensing of any domestic nuclear unit and to promulgate new regulations that could require significant capital expenditures and/or increase operating costs.
We May Not Be Able to Recover All of Our Fuel Expenses from Customers On a Timely Basis Or at All
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. 13-00380-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 Texas and New Mexico 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 re-priced energy costs for Palo Verde Unit 3 in New Mexico. In the event that recovery of fuel and purchased power expenses is denied in any 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 Fuel and Purchased Power Cost Adjustment Clause ("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, we realize a lag in the ability to reflect increases in fuel costs in our 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.
Adverse Changes in Our Credit Ratings Could Negatively Affect Our Access to the Capital Markets and our Cost of Borrowed Funds
Access to the capital markets is important to our ability to operate our business and complete our capital projects. Credit rating agencies evaluate our credit ratings on a periodic basis and when certain events occur. These ratings are premised on financial ratios and performance, our regulatory environment and rate mechanisms, resource risks and power supply costs, and other factors. A ratings downgrade could increase fees on the RCF thereby increasing the cost of funding day-to-day working capital requirements, and could also result in higher interest rates on future long-term debt. In addition, any ratings downgrade or placement of our credit ratings on negative watch could have an adverse impact on the price of our common stock. If access to capital were to become significantly constrained or costs of capital increased significantly due to lowered credit ratings, prevailing industry conditions, regulatory constraints, the volatility of the capital markets or other factors, our financial condition and results of operations could be adversely affected.
Weather Conditions Affect the Demand for Electricity or Could Result in Unplanned Outages
Our service territory is in west Texas and southern New Mexico and is particularly susceptible to dry and hot temperatures in the summer months. These seasonal weather patterns result in temperatures that can lead to daytime highs exceeding 100 degrees Fahrenheit for extended periods during the summer when we typically experience peak kWh sales at higher summer rates. Milder temperatures during this period will occur occasionally and result in less kWh sales which will adversely affect our results of operations. From time to time, we experience extreme weather conditions, including high winds (usually in the spring months but can occur during other months), that may result in unplanned outages. Under such conditions, we may incur additional costs to repair and, or, to replace equipment. Depending upon the length and extent of the damage, we may also incur additional purchase power costs. Fallen power lines and poles can cause severe damage to customer property and subject us to claims, all of which could have a material adverse effect on our results of operations and cash flows.
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 the event of unplanned outages, we must acquire power from other sources 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. Unplanned outages could also prevent us from selling excess power at wholesale. 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 may also incur additional capital and operating costs in connection with the physical security and cyber security of transmission lines and generation facilities. Damage to certain transmission and generation facilities due to vandalism or other deliberate acts, or damage due to severe weather could lead to outages or other adverse effects. We are particularly vulnerable to this because a significant portion of our available energy (at Palo Verde) 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 could have a material adverse effect on our earnings, cash flow and financial position. While we believe that we maintain adequate insurance coverage for such incidents, there is no assurance that all costs in excess of deductible amounts will be reimbursed or that we can maintain such coverage limits in the
future at competitive market rates. In the event future insurance costs and/or deductible amounts increase, our financial condition, operating results and cash flows could be materially adversely affected.
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 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 Texas Public Utility Regulatory Act ("PURA") in June 2011. The 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 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 Financial Results
We are subject to extensive federal, state and local environmental laws 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 pollution control equipment and purchases of air emission allowances and/or offsets. These laws and regulations could also result in limitations in operating hours and/or changes in construction schedules for future generating units.
Cost 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 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 increase. 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 laws or regulations. For example, the EPA has issued in the recent past various proposed regulations regarding air emissions, such as the revision of the primary and secondary ground-level ozone NAAQS. If these regulations become finalized and survive legal challenges, the cost to us to comply could adversely affect our operations and our financial results.
Climate Change and Related Legislation and Regulatory Initiatives Could Affect Demand for
Electricity or Availability of Resources, and Could Result in Increased Compliance Costs
We emit GHG (including carbon dioxide) through the operation of our power plants. Federal legislation has been introduced in both houses of Congress to regulate GHG emissions and numerous states have adopted programs to stabilize or reduce GHG emissions. Additionally, the EPA is proceeding with regulation of GHG under the CAA.
In October 2015, the EPA published a rule establishing guidelines for states to regulate carbon dioxide emissions from existing power plants, known as the Clean Power Plan ("CPP"). Legal challenges to the CPP are ongoing. On August 31, 2018, the EPA published a proposal to replace the CPP called the Affordable Clean Energy ("ACE") rule. The ACE rule has not yet been finalized. The potential impact of these GHG rules (if and when finalized) on us 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 possible to predict how any pending, proposed or future GHG legislation by Congress, the states or multi-state regions or any GHG 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.
Adverse Regulatory Decisions or Changes in Applicable Regulations or Laws Could Have a Material Adverse Effect on Our Business or Result in Significant Additional Costs
Our business is subject to extensive federal, state and local laws and regulations regarding safety and performance, siting and construction of facilities, customer service and the rates we can charge our customers, among other things. FERC regulates our wholesale operations, provision of transmission services and compliance with federally mandated reliability standards. FERC has issued a number of rules pertaining to preventing undue discrimination in transmission services and electric reliability standards. Under the Energy Policy Act of 2005, FERC can impose penalties (up to $1,238,271 per violation, per day) for failure to comply with statutes, rules and orders within FERC's jurisdiction, including mandatory electric reliability standards. Additional regulatory authorities have jurisdiction over some of our operations and construction projects, including the EPA, the DOE, the PUCT, the NMPRC and various local municipalities (including the cities of El Paso and Las Cruces).
We must periodically apply for licenses and permits from these various authorities and abide by their respective orders. Should we be unsuccessful in obtaining necessary licenses or permits or should these regulatory authorities initiate any investigations or enforcement actions or impose penalties or disallowances on us, our business could be adversely affected. Existing regulations may be revised or reinterpreted and new laws and regulations may be adopted or become applicable to us or our facilities in a manner that may have a detrimental effect on our business or result in significant additional costs because of our obligation to comply with those requirements.
In addition, our service territory borders with Mexico and as such businesses in our service territory rely heavily on commerce with businesses in Mexico. Changes in regulations or enforcement restricting such commerce activities could reduce our customer growth rate and materially adversely affect our results of operations, financial condition and cash flows.
On December 22, 2017, the Tax Cuts and Jobs Act of 2017 ("TCJA") was signed into law, enacting significant changes to the Internal Revenue Code of 1986 (as amended, the "IRC”). Key provisions impacting the Company include a reduction in the federal corporate income tax rate from 35% to 21% effective January 1, 2018, the discontinuation of bonus depreciation for regulated public utilities for assets acquired and placed into service after December 31, 2017, elimination of corporate alternative minimum tax provisions, limitations on the utilization of net operating losses ("NOL") arising after December 31, 2017 to 80% of taxable income with no carryback but with an indefinite carryforward, and additional limitations on the deductibility of executive compensation. We continue to evaluate the impact of the TCJA as regulations related to the TCJA are finalized to determine whether any of these changes could have a material adverse effect on our results of operations, financial condition, and cash flows.
Security Breaches, Criminal Activity, Terrorist Attacks and Other Disruptions to Our 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 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, system failures, computer viruses, natural disasters, a physical attack on our facilities, 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 confidential information; and could result in legal claims or proceedings, liability or regulatory penalties against us, damage our reputation or otherwise harm our business. In addition, we may be required to incur significant costs to prevent or respond to damage caused by these disruptions or security breaches in the future.
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 could lead to increased regulatory compliance costs.
As domestic and global cyber threats are on-going and increasing in sophistication, magnitude and frequency, our critical energy infrastructure may be targets of terrorist activities or otherwise could disrupt our business operations. Any such disruptions could result in significant costs to repair damaged facilities and implement increased security measures, which could have a material adverse effect on our results of operations, financial condition and/or cash flows.
We May Incur Additional Capital and Operating Costs in Connection with the Physical Security and Cyber Security of New Technologies
We operate in a highly regulated industry that requires the continued operation and development of sophisticated information technology systems and network infrastructure. The introduction of new technology and the emergence of new industry standards and technological hurdles can create unanticipated difficulties, including failures or inadequacy of equipment or software, difficulties in integrating the various components of the equipment, changes in technology, cybersecurity issues and factors outside our control, which could negatively affect our results of operations and financial condition. As we continue to develop new technology to keep up with the demands of the industry and the needs of our customers, we may be required to expend significant capital and other resources to protect against security breaches or to alleviate problems caused by security breaches.
Failure to Maintain the Security of Personally Identifiable Information Could Adversely Affect Us
In connection with our business we and our vendors, suppliers and contractors collect and retain personally identifiable information (e.g., information of our customers, shareholders, suppliers and employees), and there is an expectation that we and such third parties will adequately protect that information. The U.S. regulatory environment surrounding information security and privacy is increasingly demanding. A significant theft, loss or fraudulent use of the personally identifiable information we maintain or failure by our vendors, suppliers and contractors to use or maintain such information in accordance with contractual provisions could adversely impact our reputation and could result in significant costs, fines, litigation and loss of reputation.
The Effects of Technological Advancement, Energy Conservation Measures and Distributed Generation Could Adversely Affect Our Operations and Financial Results
New technologies may emerge that could be superior to, or may not be compatible with, some of our existing technologies, and may require us to make significant expenditures to remain competitive. Our future success will depend, in part, on our ability to anticipate and adapt to technological changes in a cost-effective manner and to offer, on a timely basis, services that meet customer demands and evolving industry standards.
Additionally, the electric utility industry is undergoing other technological advances such as the expanded cost effective utilization of energy efficiency measures, energy storage, and distributed generation including solar rooftop projects. Customers’ increased use of energy efficiency measures, energy storage, and distributed generation could result in lower demand. Reduced demand due to energy efficiency measures, energy storage, and the use of distributed generation, to the extent not substantially offset through ratemaking mechanisms, could have a material adverse impact on our financial condition, results of operations and cash flows.
Inflation Could Adversely Affect Our Financial Results
For the past several years, inflation has been relatively low and, therefore has had little impact on our results of operations and financial condition. However, should we experience increases in costs due to inflationary impacts, any delays in requesting and receiving compensatory increases in our base rates could have a material adverse impact on our financial condition, results of operations and cash flows.
Our Line of Business Is Concentrated Solely to the Electric Industry and to One Region
We are a fully vertically integrated electric utility company whose only business is the generation, transmission and distribution of electricity to customers in an area of approximately 10,000 square miles in west Texas and southern New Mexico. Approximately 87% of revenues are directly related to the retail sales of electric power to approximately 425,000 residential, commercial and public authority customers. As such, risks uniquely associated with the utility industry such as changes in utility legislation and regulations, weather patterns in the region and economic conditions will have a greater effect on our overall operating results than otherwise if our operations were more diversified into other lines of business and in a broader geographical area.
The Operation of Transmission Lines on Public and Private Properties, including Indian Lands, Could Result in Uncertainty Related to Continued Easements and Rights-of-way and Significantly Impact Our Business
Portions of our transmission lines are located on public and private properties, including Indian lands, pursuant to easements or other rights-of-way that are effective for specified periods. We are unable to predict the final outcome of pending or future approvals by applicable property owners and governing bodies with respect to renewals of these easements and rights-of-way.
Failure to Successfully Operate Our Facilities or Perform Certain Corporate Functions May Adversely Affect Our Operations and Financial Condition
Our performance depends on the successful operation of our facilities. Operating these facilities involves many risks, including:
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operator error or failure of equipment or processes, including failure to follow appropriate safety protocols;
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the handling of hazardous equipment or materials that could result in serious personal injury, loss of life and environmental and property damage;
•
operating limitations that may be imposed by environmental or other regulatory requirements;
•
labor disputes;
•
information technology or financial system failures, including those due to the implementation and integration of new technology, that impair our information technology infrastructure, reporting systems or disrupt normal business operations;
•
information technology failure that affects our ability to access customer information or causes us to lose confidential or proprietary data that materially and adversely affects our reputation or exposes us to legal claims; and
•
catastrophic events such as fires, earthquakes, explosions, leaks, floods, droughts, natural disasters, terrorism, pandemic health events or other similar occurrences, which may require participation in mutual assistance efforts by us or other utilities to assist in power restoration efforts.
Such events may result in a decrease or elimination of revenue from our facilities, an increase in the cost of operating our facilities or delays in cash collections, any of which could have a material adverse effect on our results of operations, financial condition and/or cash flows.
Our Success Depends on the Availability of the Services of a Qualified Workforce and Our Ability to Attract and Retain Qualified Personnel and Senior Management
Our workforce is aging and many employees have retired in the last few years or are or will become eligible to retire within the next few years. Although we have undertaken efforts to recruit and train new field service personnel, we may be faced with a shortage of experienced and qualified personnel. Our costs, including costs to replace employees, benefit (including healthcare) costs, retirement costs, productivity costs and safety costs, may rise. Failure to hire and adequately train replacement employees, including the transfer of significant internal historical knowledge and expertise to the new employees, or the future availability and cost of contract labor may adversely affect the ability to manage and operate our business. If we are unable to successfully attract and retain an appropriately qualified workforce, our results of operations could be negatively affected.
A substantial number of our employees are covered by a collective bargaining agreement that is scheduled to expire in September 2019. Labor disruptions could occur depending on the outcome of negotiations to renew the terms of this agreement with the union or if a tentative new agreement is not ratified by its members. In addition, some of our non-represented employees could join this union in the future. Labor disruptions, strikes or significant negotiated wage and benefit increases, whether due to union activities, employee turnover or otherwise, could have a material adverse effect on our business, results of operations and/or cash flows.
We depend on our senior management and other key personnel. Our success depends on our ability to attract and retain key personnel. The inability to recruit and retain or effectively transition key personnel or the unexpected loss of key personnel may adversely affect our operations. In addition, because of the reliance on our management team, our future success depends in part on our ability to identify and develop talent to succeed senior management. Any such occurrences could negatively impact our financial condition and results of operations.
Our Ability to Accurately Report Our Financial Results or Prevent Fraud May Be Adversely Affected if We Fail to Maintain an Effective System of Internal Controls
Effective internal controls are necessary for us to provide reliable financial reports, effectively prevent fraud and operate successfully as a public company. If our efforts to maintain an effective system of internal controls are not successful, we are unable to maintain adequate controls over our financial reporting and processes in the future or we are unable to comply with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002, our operating results could be harmed, or we may fail to meet
our reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our common stock and other securities.
Insufficient Insurance Coverage and Increased Insurance Costs Could Adversely Affect Our Operations and Financial Results
We currently have general liability and property insurance in place to cover certain of our facilities in amounts that we consider appropriate. Such policies are subject to certain limits and deductibles and do not include business interruption coverage. Insurance coverage may not be available in the future at current costs or on commercially reasonable terms, and the insurance proceeds received for any loss of, or any damage to, any of our facilities may not be sufficient to restore the loss or damage without negative impact on our results of operations, financial condition and cash flows.
We Are Subject to Costs and Other Effects of Legal and Regulatory Proceedings, Disputes and Claims
From time to time in the normal course of business, we are subject to various lawsuits, audits, regulatory proceedings, disputes, and claims that could result in adverse judgments or settlements, fines, penalties, injunctions, or other adverse consequences. These matters are subject to a number of uncertainties, and management is often unable to predict the outcome of such matters; resulting liabilities could exceed amounts currently reserved or insured against with respect to such matter. The legal costs and final resolution of matters in which we are involved could have a reputational impact and/or a short- or long-term negative effect on our results of operations, financial condition and/or cash flows. Similarly, the terms of resolution could require us to change our operational practices and procedures, which could also have a material adverse effect on our results of operations, financial condition and/or cash flows.
Provisions in Our Corporate Documents, Franchise Agreements and State Law Could Delay or Prevent a Change in Control of the Company, Even if That Change Would Be Beneficial to Our Shareholders
Our Articles of Incorporation and Bylaws contain provisions that may make acquiring control of the Company difficult and could preclude our shareholders from receiving a change of control premium, including:
•
provisions relating to the classification, nomination and removal of our directors;
•
provisions regulating the ability of our shareholders to bring matters for action at annual meetings of our shareholders;
•
provisions limiting the ability to call special meetings of the shareholders to the Chairman of the Board, our President and Chief Executive Officer, our Secretary, the majority of the Board of Directors or the holders of at least 25% of the outstanding shares of our capital stock entitled to vote at such meeting;
•
provisions restricting our ability to engage in a wide range of “Business Combination” transactions with an “Interested Shareholder” (generally, any person who owns 15% or more of our outstanding voting power) or any affiliate or associate of an Interested Shareholder, unless specific conditions are met; and
•
the authorization given to our Board of Directors or any duly designated committee to issue and set the terms of preferred stock.
Our El Paso franchise agreement states that any assignment of the franchise agreement, including a deemed assignment as a result of a change in control of the Company, requires the consent of the City of El Paso. In addition, approval of the NMPRC, PUCT and FERC would likely be required in any transaction involving a change of control.
In addition, Texas law prohibits us from engaging in a business combination with any shareholder for three years from the date that person became an affiliated shareholder by beneficially owning 20% or more of our outstanding common stock, in the absence of certain board of director or shareholder approvals.
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 and distribution lines are located either on company-owned land, private rights-of-way, easements or on streets or highways by public consent.
The Company owns an executive and administrative office building and various operations centers in El Paso County, Texas, and Doña Ana County, New Mexico. The Company leases land in El Paso, Texas, adjacent to Newman under a lease that expires in June 2033, subject to a renewal option of 25 years. The Company has several other leases for office and parking facilities that expire within the next five years.
Item 3.
Item 3.
Legal Proceedings
The Company is involved in various legal, environmental, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies regarding matters arising in the ordinary course of business. In many of these matters, the Company has excess casualty liability insurance that covers the various claims, actions and complaints. The Company regularly analyzes current information and, as necessary, makes provisions in its financial statements for probable liabilities for the eventual disposition of these matters. While the outcome of these matters cannot be predicted with certainty, based upon a review of the matters and applicable insurance coverage, the Company believes that none of these matters will have a material adverse effect on the financial position, results of operations or cash flows of the Company.
See Part I, Item 1, "Business - Environmental Matters" and Part II, Item 8, "Financial Statements and Supplementary Data, Note D, Note M and Note L of Notes to Financial Statements" for further discussion of the effects of government legislation and regulation on the Company as well as certain pending legal proceedings.
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."
Performance Graph
The following graph compares the performance of the Company’s common stock to the performance of Edison Electric Institute’s ("EEI") index of investor-owned electric utilities and the NYSE Composite, setting the value of each at December 31, 2013 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 Composite, as reflected in the graph.
As of January 31, 2019, there were 2,176 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 $57.5 million in cash dividends during the twelve months ended December 31, 2018. On January 31, 2019, the Board of Directors declared a quarterly cash dividend of $0.36 per share payable on March 29, 2019, to shareholders of record as of the close of business on March 15, 2019. Typically, the Board of Directors reviews the Company’s dividend policy annually in the second quarter of each year. Declaration and payment of dividends is subject to compliance with certain financial tests under Texas law. Since 1999, the Company has also returned cash to shareholders 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. 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 ("2011 Plan"). No shares of common stock were repurchased during the twelve months ended December 31, 2018, under the 2011 Plan. The table below provides the amount of the fourth quarter issuer purchases of equity securities.
_____________________
(a) Represents shares of common stock delivered to us as payment of withholding taxes due upon the vesting of
restricted stock held by our employees, not considered part of the 2011 Plan.
On January 30, 2019, the Company submitted an application with both the NMPRC and the FERC seeking approval to issue shares of common stock, including the reissuance of treasury shares, in an amount up to $200.0 million in one or more transactions. In order to align the number of shares of common stock held as treasury stock by the Company with various regulatory applications, filings and orders, on January 31, 2019, the Board of Directors of the Company approved the cancellation of 1.4 million shares of Common Stock held as treasury shares by the Company effective upon the later of approval by the FERC of the accounting treatment of the cancellation and March 31, 2019.
For Equity Compensation Plan Information see Part III, Item 12, "Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters."
Item 6.
Item 6.
Selected Financial Data
As of and for the following periods (in thousands except for share and per share data):
________________
(a)
Effective January 1, 2018, the Company implemented Accounting Standards Update ("ASU") 2016-01, Financial Instruments - Overall: Recognition and Measurement of Financial Assets and Liabilities. As required by the new standard, changes in the fair values of the Company's equity investments are recognized in earnings, whereas prior to 2018, such changes were recognized in accumulated other comprehensive income ("AOCI").
(b)
The Company implemented ASU 2017-07, Compensation - Retirement Benefits (Topic 715), in the first quarter of 2018, and as required by the standard, reclassified certain amounts in the financial statements for 2017 and 2016.
(c)
The Company implemented ASU 2016-15, Statement of Cash Flows (Topic 230) in the first quarter of 2018, and as required by the standard, reclassified certain amounts in the financial statements for 2017 and 2016.
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 of Financial Condition and Results of Operations, please refer to our Financial Statements and the accompanying notes, which contain our operating results.
Summary of Critical Accounting Policies and Estimates
Our financial statements have been prepared in conformity with U.S. Generally Accepted Accounting Principles ("GAAP"). Part II, Item 8, Financial Statements and Supplementary Data, Note A of Notes to 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. The Company evaluates its estimates on an on-going basis, including those related to depreciation, unbilled revenue, income taxes, fuel costs, pension and other post-retirement obligations and asset retirement obligations ("ARO"). 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, 2018, we had recorded regulatory assets currently subject to recovery in future rates of approximately $81.8 million and regulatory liabilities of approximately $313.3 million as discussed in greater detail in Part II, Item 8, Financial Statements and Supplementary Data, Notes E and K of Notes to Financial Statements. Regulatory tax assets of approximately $20.2 million related to the regulatory treatment of the equity portion of Allowance for Funds Used During Construction ("AFUDC") and approximately $19.3 million related to excess deferred state income taxes are included in regulatory assets. Regulatory tax liabilities of approximately $299.4 million, primarily related to the reduction of the corporate tax rate from 35% to 21%, are included in regulatory liabilities and will be refunded to customers.
In the event we determine that we can no longer apply the Financial Accounting Standards Board's ("FASB") guidance for regulated operations to all or a portion of our operations or to the individual regulatory assets recorded, based on regulatory action, we could be required to record a charge against income in the amount of the unamortized balance of the related regulatory assets. Such an action could materially reduce our total assets, specifically our total deferred charges and other assets, and 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 on a periodic basis every one to three years. The NMPRC, in its discretion, may order that a prudence review be conducted to assure that fuel and purchased power costs recovered from customers are prudently incurred. Prior to the completion of a reconciliation proceeding or audit by the PUCT or the NMPRC, we record fuel transactions such that fuel revenues, including fuel costs recovered through the FPPCAC in New Mexico, equal fuel expense. In the event that a disallowance of fuel cost recovery occurs during a reconciliation proceeding or an audit, 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.
On September 27, 2016, the Company filed an application with the PUCT, designated as PUCT Docket No. 46308, to reconcile $436.6 million of Texas fuel and purchased power expenses incurred during the period of April 1, 2013 through March 31, 2016. On June 29, 2017, the PUCT approved a settlement in this proceeding. The settlement provides for the reconciliation of fuel and purchased power costs incurred from April 1, 2013 through March 31, 2016. As of December 31, 2018, Texas jurisdictional fuel and purchased power costs subject to prudence review are costs from April 1, 2016 through December 31, 2018 that total approximately $353.4 million. The Company's request to reconcile its fuel and purchased power costs for the period January 1, 2013 through December 31, 2014 was approved in the NMPRC Final Order. New Mexico jurisdictional costs subject to prudence review are costs from January 1, 2015 through December 31, 2018 that total approximately $206.8 million.
The Company recovers fuel and purchased power costs from the Rio Grande Electric Cooperative ("RGEC") pursuant to an ongoing contract with a two-year notice to terminate provision. The contract includes a fuel adjustment clause designed to recover all eligible fuel and purchased power costs allocable to the RGEC and is updated on an annual basis. This update is reviewed and
approved by the RGEC annually in February following the prior calendar year. As of December 31, 2018, the RGEC fuel costs subject to prudence review were approximately $1.1 million.
Decommissioning Costs and Estimated Asset Retirement Obligation
Pursuant to the ANPP Participation Agreement, the rules and regulations of the NRC and federal law, we must fund our share of the estimated costs to decommission Palo Verde Units 1, 2, 3 and associated common areas. The determination of the estimated liability is based on site-specific estimates, which are updated every three years and involve numerous judgments and assumptions, including estimates of future decommissioning costs at current price levels, escalation rates and discount rates. The Palo Verde ARO is approximately $98.8 million and represents approximately 98% of our total ARO balance of $101.1 million as of December 31, 2018. A 10% increase in the estimates of future Palo Verde decommissioning costs at current price levels would have increased the ARO liability by approximately $10.9 million at December 31, 2018. See Part II, Item 8, Financial Statements and Supplementary Data, Note F of Notes to Financial Statements for further discussion.
We are required to fund estimated nuclear decommissioning costs over the life of the generating facilities through the use of external trust funds pursuant to rules of the NRC, PUCT and the ANPP Participation Agreement. Historically, in Texas and New Mexico, we have been permitted to collect the funding requirements for our NDT as part of our rates, except for a portion of Palo Verde Unit 3, which is deregulated in the New Mexico jurisdiction. While we periodically attempt to seek to recover the costs of decommissioning obligations through our rates, we are not able to conclude, given the currently available evidence, that it is probable these costs will continue to be collected over the period until decommissioning begins in 2044. We are ultimately responsible for these costs, and our future actions combined with future decisions from regulators will determine how successful we are in this effort.
The funding amounts are based on assumptions about future investment returns and future decommissioning cost escalations. If the rates of return earned by the trusts fail to meet expectations or if estimated costs to decommission the nuclear plant increase beyond our expectations, we would be required to increase our funding to the NDT.
The NDT consists 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 $134.2 million as of December 31, 2018. A hypothetical 10% increase in interest rates would have reduced the fair values of these funds by $1.7 million at December 31, 2018. The NDT also includes marketable equity securities of approximately $135.9 million at December 31, 2018. A hypothetical 10% decrease in equity prices would have reduced the fair values of these funds by $13.6 million at December 31, 2018. Declines in market prices could require that additional amounts be contributed to our NDT to maintain minimum funding requirements.
We do not anticipate expending monies held in the NDT before 2044 or a later period when decommissioning of Palo Verde begins.
Future Pension and Other Post-retirement Obligations
We maintain a qualified noncontributory defined benefit pension plan, which covers substantially all of our employees, and two non-funded nonqualified supplement plans that provide benefits in excess of amounts permitted under the provisions of the tax law for certain participants in the qualified plan. We also sponsor a plan that provides other post-retirement benefits, such as health and life insurance benefits to retired employees. Our net obligations under these various benefit plans at December 31, 2018 totaled $114.0 million and are recorded as liabilities on our balance sheet. The net periodic benefit costs for these plans totaled $2.2 million for the twelve months ended December 31, 2018.
Our pension and other post-retirement benefit liabilities and the related net periodic benefit costs are calculated on the basis of a number of actuarial assumptions regarding discount rates, expected return on plan assets, rate of compensation increase, life expectancy of retirees and health care cost inflation. For 2018, the discount rates used to measure our year end liabilities are based on a segmented spot rate yield curve that matches projected future payments with the appropriate interest rate applicable to the timing of the projected future benefit payments. As of December 31, 2018, the corresponding weighted-average discount rates range from 4.11% to 4.45% depending upon the benefit plan.
Our overall expected long-term rate of return on assets for the pension trust fund is 7.5% as of January 1, 2019, which is both a pre-tax and after-tax rate as pension funds are generally not subject to income tax. Our overall expected long-term rate of return on assets for the other post-retirement benefits trust, on an after-tax basis, is 6.00% as of January 1, 2019. Both expected long-term rates of return are based on the after-tax weighted average of the expected returns on investments. The expected returns on investments in the pension trust and the other post-retirement benefits trust are based upon the target asset allocations for the two trusts.
Our accrued post-retirement benefit liability and the service and interest components of the related net periodic benefit costs are calculated using an actuarial assumption regarding health care cost inflation. For measurement purposes, a 6.0%, 7.0%, 4.5% and 8.5% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2019 for pre-65 medical, pre-65 drug, post-65 medical and post-65 drug, respectively. The health care cost trend rates are assumed to decline steadily to an ultimate rate of 4.5% by 2025 for pre-65 medical and by 2026 for pre-65 and post-65 drug. Post-65 medical trend is assumed to be 4.5% for all years into the future. Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plan.
The estimated rate of compensation increase used in our retirement plans is 4.5% and is based on recent trends for all non-union employees and the amounts we are contractually obligated for union employees.
The following table reflects the sensitivities that a change in certain actuarial assumptions would have had on the December 31, 2018 reported pension liability and our 2018 reported pension expense (in thousands):
The following chart reflects the sensitivities that a change in certain actuarial assumptions would have had on the December 31, 2018 other post-retirement benefit obligation and our 2018 reported other post-retirement benefit expense (in thousands):
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 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 financial statements. On December 22, 2017, the TCJA was enacted. Substantially all of the provisions of the TCJA are effective for taxable years beginning after December 31, 2017. The TCJA includes significant changes to the IRC, including amendments which significantly change the taxation of business entities and includes specific provisions related to regulated public utilities. See Part II, Item 8, Financial Statements and Supplementary Data, Note K of Notes to Financial Statements for further discussion.
When appropriate, we record a valuation allowance against deferred tax assets to reflect that these tax assets may not be realized. In assessing the likelihood of the realization of deferred tax assets, management considers the estimated amount and character of future taxable income. Significant changes in these judgments and estimates could have a material impact on the results of operations and financial position of the Company. There were no valuation allowances for deferred tax assets as of December 31, 2018.
We recognize tax benefits that are more likely than not to be sustained upon examination by tax authorities. The amount recognized is measured as the largest amount of benefit that is greater than 50% likely to be realized upon settlement. The unrecognized tax benefits that do not meet the recognition and measurement standards were $3.2 million as of December 31, 2018.
Overview
The following is an overview of our results of operations for the years ended December 31, 2018, 2017 and 2016. Net income and basic earnings per share for the years ended December 31, 2018, 2017 and 2016 are shown below:
The following table and accompanying explanations show the primary factors affecting the after-tax change in income between the calendar years ended December 31, 2018 and 2017, 2017 and 2016, and 2016 and 2015 (in thousands):
______________________
Footnotes reflect pre-tax amounts
(a)
Investment and interest income, NDT decreased in 2018, primarily due to net realized and unrealized losses on securities held in the NDT. Beginning on January 1, 2018, the Company adopted ASU 2016-01, Financial Instruments, and began recording unrealized gains and losses on equity securities held in the NDT directly in earnings. Refer to "Impact of New Accounting Standards and Use of Non-GAAP Financial Measures" for further details.
(b)
Investment and interest income, NDT increased in 2017 and decreased in 2016, primarily due to changes in realized gains on securities sold from the NDT. Sales of such securities are primarily the result of the Company's efforts to re-balance and further diversify the NDT investments.
(c)
Depreciation and amortization increased primarily due to increases in plant.
(d)
Depreciation and amortization increased primarily due to increases in plant, including MPS Units 3 and 4, which were placed in service in 2016. These increases were partially offset by the sale of the Company's interest in Four Corners in July 2016.
(e)
Depreciation and amortization decreased primarily due to (i) a reduction of approximately $10.9 million resulting from changes in depreciation rates approved in the PUCT Final Order in Docket No. 44941 ("2016 PUCT Final Order") and the NMPRC Final Order and (ii) the sale of the Company's interest in Four Corners in 2016. These decreases were partially offset by an increase in plant, primarily due to MPS Units 1 and 2 and the Eastside Operations Center ("EOC") each being placed in service in March 2015, and MPS Units 3 and 4 being placed in service in May 2016 and September 2016, respectively.
(f)
Palo Verde performance rewards, associated with the 2013 to 2015 performance periods, net of disallowed fuel and purchased power costs related to the resolution for the Texas fuel reconciliation proceeding designated as PUCT Docket No. 46308 for the period from April 2013 through March 2016, were recorded in June 2017, with no comparable amounts in 2018 or 2016.
(g)
O&M expenses at our fossil-fuel generating plants increased primarily due to outage costs at Rio Grande Unit 8 in 2018.
(h)
Interest on long-term debt (net of capitalized interest) and other increased, primarily due to the $125.0 million aggregate principal amount of 4.22% Senior Notes issued in June 2018 and due in August 2028, partially offset by the redemption of $33.3 million of 2012 Series A 1.875% Pollution Control Bonds ("PCBs") in 2017.
(i)
Interest on long-term debt (net of capitalized interest) and other increased, primarily due to the $150.0 million principal amount of senior notes issued in March 2016 and an increase in short term borrowings for working capital purposes in 2017.
(j)
Interest on long-term debt (net of capitalized interest) and other increased, primarily due to the $150.0 million principal amount of senior notes issued in March 2016.
(k)
Retail non-fuel base revenues decreased primarily due to refunds of approximately $28.2 million for the reduction in the federal corporate income tax rate due to the TCJA, partially offset by a $7.7 million base rate increase compared to 2017
base rate increase related to the 2017 PUCT Final Order. Excluding the impact of rate changes, retail non-fuel base revenues in 2018, increased by $19.8 million primarily due to an increase in kWh sales that resulted from favorable weather and an increase in the average number of customers served.
(l)
Retail non-fuel base revenues increased primarily due to the non-fuel base rate increase approved in the 2017 PUCT Final Order. 2017 included approximately $8.8 million of retail non-fuel base revenues for the period from July 18, 2017 through December 31, 2017, which was recognized when the 2017 PUCT Final Order was approved in December 2017. Excluding the $8.8 million 2017 PUCT Final Order impact, retail non-fuel base revenues increased $4.5 million, or 0.7%, in 2017 compared to 2016.
(m)
Retail non-fuel base revenues increased primarily due to the recognition of $40.9 million related to the 2016 PUCT Final Order.
(n)
Taxes other than income taxes increased primarily due to increased property valuations in Texas as a result of MPS Units 3 and 4 being placed in service in 2016 and increased revenue related taxes in Texas.
(o)
Taxes other than income taxes increased primarily due to increased property tax rates and valuations in Texas as a result of MPS Units 1 and 2 and the EOC being placed in service during the first quarter of 2015 and increased billed revenues for Texas revenue related taxes. These increases were partially offset by decreased property taxes in Arizona due to lower property values.
(p)
The effective tax rate, other decreased primarily due to the TCJA that reduced the federal corporate income tax rate from 35% to 21%, excluding the tax impact of other items in the table above partially offset by a reduction in state tax reserves in 2017 due to the favorable settlement of Texas state income tax audits.
(q)
The effective tax rate, other decreased primarily due to favorable settlements of state income tax audits in Texas and Arizona.
(r)
The effective tax rate, other increased primarily due to the change to normalize state income taxes in accordance with the 2016 PUCT Final Order and the NMPRC Final Order.
(s)
Palo Verde O&M expenses decreased primarily due to lower incentives and administrative and general ("A&G") benefits in 2018 compared to 2017.
(t)
Palo Verde O&M expenses increased primarily due to higher A&G expenses.
(u)
AFUDC decreased due to lower balances of construction work in progress ("CWIP"), primarily due to MPS Units 3 and 4 being placed in service in May and September 2016, respectively, and a reduction in the AFUDC rate effective January 2017.
(v)
AFUDC decreased due to lower balances of CWIP, primarily due to the MPS units and the EOC being placed in service in 2015 and 2016, and a reduction in the AFUDC rate effective January 2016 as a result of the 2016 PUCT Final Order.
Impact of New Accounting Standard and Use of Non-GAAP Financial Measures
Upon adoption of ASU 2016-01, Financial Instruments - Recognition and Measurement of Financial Assets and Financial Liabilities, the Company recorded, as of January 1, 2018, a cumulative effect adjustment to retained earnings of $41.0 million, net of tax, for the unrealized gains (losses) related to equity securities held in the NDT. As required by ASU 2016-01, changes in the fair value of equity securities are now recognized in the Company's Statements of Operations. The adoption of the new standard added the potential for significant volatility to the Company's reported results of operations as changes in the fair value of equity securities may occur. Furthermore, the equity investments included in the NDT are significant and are expected to increase significantly during the remaining life (estimated to be 27 to 30 years) of Palo Verde. Accordingly, the Company has provided the following non-GAAP financial measures, which reconcile GAAP net income to non-GAAP adjusted net income and GAAP basic earnings per share to non-GAAP adjusted basic earnings per share, to exclude the impact of changes in fair value of equity securities and realized gains (losses) from the sale of both equity and fixed income securities.
Adjusted net income and adjusted basic earnings per share are not measures of financial performance under GAAP and should not be considered as an alternative to net income and earnings per share, respectively. Furthermore, the Company's presentation of any non-GAAP financial measure may not be comparable to similarly titled measures used by other companies. The Company believes adjusted net income and adjusted basic earnings per share are useful financial measures for investors and analysts in understanding the Company's core operating performance because each measure removes the effects of variances reported in the Company's results of operations that are not indicative of fundamental changes in the earnings capacity of the Company.
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 to our sole full requirement customer (which are FERC-regulated cost-based wholesale sales within our service territory), accounted for less than 1% of revenues in each of 2018, 2017 and 2016.
Revenues from the sale of electricity include fuel costs that are recovered from our customers through fuel adjustment mechanisms. Prior to 2017, a significant portion of fuel costs have been recovered through base rates in New Mexico. Effective July 1, 2016, with the implementation of the NMPRC Final Order, fuel costs are no longer recovered through base rates. Beginning July 1, 2016, all fuel costs are recovered through a fuel adjustment mechanism. 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 3% of our non-fuel base revenues during such periods. As shown in the table above, residential and small commercial customers represent approximately 79% 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 structures in Texas and New Mexico reflect 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 2018, 2017 and 2016.
Customer growth is a key driver of the growth of retail sales. The average number of retail customers grew 1.6% and 1.7% in 2018 and 2017, respectively. See the tables presented on pages 35 and 36 which provide detail on the average number of retail customers and the related revenues and kWh sales.
Retail non-fuel base revenues. For the twelve months ended December 31, 2018, retail non-fuel base revenues decreased primarily due to the refunds in 2018 of approximately $28.2 million to customers for the reduction in the federal corporate income tax rate due to the TCJA, partially offset by a $7.7 million base rate increase related to the 2017 PUCT Final Order. Excluding the impact of rate changes related to the 2017 PUCT Final Order, retail non-fuel base revenues increased by $19.8 million, or 3.2%, compared to the twelve months ended December 31, 2017. This increase was primarily due to (i) increased revenues from residential customers of $17.1 million caused by a 5.9% increase in kWh sales that resulted from favorable weather and a 1.7% increase in the average number of residential customers served, and (ii) increased revenues from small commercial and industrial customers of $2.9 million that resulted from favorable weather and a 0.9% increase in the average number of small commercial and industrial customers served. Cooling degree days increased 8.8% in the twelve months ended December 31, 2018, when compared to the twelve months ended December 31, 2017, and were 10.9% above the 10-year average. Heating degree days increased 27.3% in the twelve months ended December 31, 2018, when compared to the twelve months ended December 31, 2017, and were 5.8% below the 10-year average.
For the twelve months ended December 31, 2017, retail non-fuel base revenues increased primarily due to the recognition of $8.8 million approved in the 2017 PUCT Final Order. Excluding the $8.8 million 2017 PUCT Final Order impact, for the twelve months ended December 31, 2017, retail non-fuel base revenues increased $4.5 million, or 0.7%, compared to the twelve months ended December 31, 2016. This increase was primarily due to increased revenues from residential customers of $2.5 million driven by a 1.6% increase in the average number of residential customers served and increased revenues from small commercial and industrial customers of $2.1 million driven by a 2.4% increase in the average number of small commercial and industrial customers served. The Company experienced an overall 1.7% increase in the average number of customers served, partially offset by milder weather when compared to the twelve months ended December 31, 2016. Heating degree days decreased 17.8% in the twelve months ended December 31, 2017, when compared to the twelve months ended December 31, 2016. During our peak summer cooling season, cooling degree days in 2017 were comparable to the same period in 2016.
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) prior to July 1, 2016, fuel costs recovered in base rates in New Mexico. In New Mexico, effective July 1, 2016, with the implementation of the NMPRC Final Order, fuel and purchased power costs are no longer recovered through base rates, as they were historically, but are recovered through the FPPCAC. Fuel and purchased power costs are reconciled to actual costs on a monthly basis and recovered or refunded to customers the second succeeding month. Additionally, effective January 1, 2018, pursuant to the final order in NMPRC Case No. 17-00090-UT, the RPS costs for New Mexico are recovered through a separate RPS Cost Rider and not through the FPPCAC. The RPS Cost Rider is updated in an annual NMPRC filing, including a true-up of the prior calendar year’s RPS costs and RPS Cost Rider revenue. In Texas, fuel costs are recovered through a fixed fuel factor. We can seek to revise our Texas fixed fuel factor based upon an 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 defined as material when they exceed 4% of the previous twelve months' fuel costs.
In March 2018 and March 2017, $1.1 million and $1.4 million, respectively, were credited to customers through the applicable fuel adjustment clauses as the result of a reimbursement from the DOE related to spent nuclear fuel storage.
We over-recovered fuel costs by $4.8 million in the twelve months ended December 31, 2018. We over-recovered fuel costs by $17.1 million and under-recovered fuel costs by $14.9 million in the twelve months ended December 31, 2017 and 2016, respectively. At December 31, 2018, we had a net fuel over-recovery balance of $11.0 million, including over-recoveries of $8.9 million in Texas, $2.0 million in New Mexico and $0.1 million in FERC jurisdictions. On October 13, 2017, we filed a request to decrease our Texas fixed fuel factor by approximately 19% to reflect decreased fuel expenses primarily related to a decrease in the price of natural gas used to generate power. The decrease in our Texas fixed fuel factor became effective beginning with the November 2017 billing month. On April 13, 2018, we filed a request with the PUCT to decrease the Texas fixed fuel factor by approximately 29% to reflect decreased fuel expenses primarily related to a decrease in the price of natural gas used to generate power. On April 25, 2018, our proposed fuel factors were approved on an interim basis effective for the first billing cycle of the May 2018 billing month. The revised factor was approved and the docket closed on May 22, 2018. On October 15, 2018, we filed a request with the PUCT to decrease our Texas fixed fuel factor by approximately 6.99% to reflect decreased fuel expenses primarily related to a decrease in the price of natural gas used to generate power. On October 25, 2018, our fixed fuel factor was approved on an interim basis effective for the first billing cycle of the November 2018 billing month. The revised factor was approved by the PUCT and the docket closed on November 19, 2018. The Texas fixed fuel factor will continue thereafter until changed by the PUCT.
Off-system sales. Off-system sales are sales into wholesale 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 have shared 100% of margins on non-arbitrage sales (as defined by the settlement in PUCT Docket No. 41852) and 50% of margins on arbitrage sales with our Texas customers since April 1, 2014. We are currently sharing 90% of off-system sales margins with our New Mexico customers (as reaffirmed in NMPRC Case No. 09-00171-UT), and 25% of our off-system sales margins with our sales for resale - full requirement customer under the terms of their contract.
Typically, we realize a significant portion of our off-system sales margins in the first and fourth 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. A decrease in natural gas market prices coupled with an increase in wholesale power market prices allowed us to engage in additional off-system sales in the third quarter of 2018 and in the third quarter of 2017. Palo Verde's availability is an important factor in realizing these off-system sales margins.
The table below shows megawatt-hours ("MWhs"), sales revenue, fuel cost, total margins and retained margins made on off-system sales for the twelve months ended December 31, 2018, 2017 and 2016 (in thousands, except for MWhs).
Off-system sales revenue increased $27.4 million, or 46.5%, and the related retained margins increased $0.5 million, or 27.3%, for the twelve months ended December 31, 2018, when compared to the twelve months ended December 31, 2017, as a result of a 31.6% increase in MWh sales due to additional available power, and higher average market prices for power. Off-system sales revenue increased $13.3 million, or 29.1%, and the related retained margins increased $0.5 million, or 47.1%, for the twelve months ended December 31, 2017, when compared to the twelve months ended December 31, 2016, as a result of higher average market prices for power and a 6.0% increase in MWh sales due to additional available power.
Comparisons of kWh sales and operating revenues are shown below:
___________________________
(1)
2018 includes $7.7 million of additional revenues compared to 2017 resulting from the 2017 PUCT Final Order, which increased base rates effective July 18, 2017.
(2)
2018 includes a $28.2 million base rate decrease related to the reduction in the federal statutory income tax rate enacted under the TCJA.
(3)
Includes the portion of DOE refunds related to spent fuel storage of $1.1 million and $1.4 million in 2018 and 2017, respectively, that were credited to customers through the applicable fuel adjustment clauses.
(4)
2017 includes $5.0 million related to the Palo Verde performance rewards, net.
(5)
Includes deregulated Palo Verde Unit 3 revenues for the New Mexico jurisdiction of $8.1 million and $9.8 million in 2018 and 2017, respectively.
(6)
Includes retained margins of $2.1 million and $1.7 million in 2018 and 2017, respectively.
(7)
Represents revenues with no related kWh sales.
(8)
The Company implemented ASU 2014-09, Revenue from Contracts with Customers, in the first quarter of 2018, and following the adoption of the standard, revenues related to reimbursed costs of energy efficiency programs approved by the Company's regulators are reported in operating revenues from customers. Related expenses are reported in O&M expenses.
(9)
Includes energy efficiency bonuses of $1.3 million and $1.5 million in 2018 and 2017, respectively.
(10)
The number of retail customers presented is based on the number of service locations.
_______________________
(1)
2017 includes $8.8 million of relate back revenues in Texas from July 18, 2017 through December 31, 2017, which was recorded in the fourth quarter of 2017 related to the 2017 PUCT Final Order.
(2)
Includes the portion of DOE refunds related to spent fuel storage of $1.4 million and $1.6 million in 2017 and 2016, respectively, that were credited to customers through the applicable fuel adjustment clauses.
(3)
Historically, fuel and purchased power costs in the New Mexico jurisdiction were recorded through base rates and a FPPCAC that accounts for the changes in the costs of fuel relative to the amount included in base rates. Effective July 1, 2016, with the implementation of the NMPRC Final Order, these costs are no longer recovered through base rates but are recovered through the FPPCAC.
(4)
2017 includes $5.0 million related to the Palo Verde performance rewards, net.
(5)
Includes deregulated Palo Verde Unit 3 revenues for the New Mexico jurisdiction of $9.8 million and $8.7 million in 2017 and 2016, respectively.
(6)
Includes retained margins of $1.7 million and $1.1 million in 2017 and 2016, respectively.
(7)
Represents revenues with no related kWh sales.
(8)
Includes an energy efficiency bonuses of $1.5 million and $0.5 million in 2017 and 2016, respectively.
(9)
The number of retail customers presented is based on the number of service locations.
Fuel and purchased power expense
Our sources of energy include electricity generated from our nuclear and natural gas generating plants and purchased power. Palo Verde represents approximately 30% of our net dependable generating capacity and approximately 49% of our Company-generated energy for the twelve months ended December 31, 2018. Fluctuations in the price of natural gas, which is also the primary factor influencing the price of purchased power, have had a significant impact on our cost of energy.
Fuel and purchased power expense decreased $15.6 million, or 6.4%, for the twelve months ended December 31, 2018 compared to the twelve months ended December 31, 2017, primarily due to (i) decreased natural gas costs of $12.6 million primarily due to a 30.4% decrease in the average cost of MWhs generated, partially offset by a 30.9% increase in the MWhs generated with natural gas, and (ii) decreased nuclear fuel costs of $3.1 million primarily due to a reduction in the price of uranium and a 3.8% decrease in the MWhs generated with nuclear fuel.
Fuel and purchased power expense increased $11.3 million, or 4.8%, for the twelve months ended December 31, 2017 compared to the twelve months ended December 31, 2016, primarily due to increased natural gas costs of $18.4 million due to an 8.2% increase in the MWhs generated with natural gas and a 6.2% increase in the average cost of MWhs generated. This increase in fuel and purchased power expense was partially offset by decreased coal costs of $5.6 million as a result of the sale of our interest in Four Corners, a coal-fired generation station, in July 2016.
The table below details the sources and costs of energy for 2018, 2017 and 2016.
__________________
(a) The sale of our interest in Four Corners, a coal-fired generation station, closed on July 6, 2016. The cost includes the amortization of deferred coal mine reclamation obligations.
(b) Costs include a DOE refund related to spent fuel storage of $1.2 million, $1.6 million and $1.8 million recorded in 2018, 2017 and 2016, respectively. Cost per MWh excludes these refunds.
Operations and maintenance expense
O&M expense increased $14.6 million, or 4.6%, in 2018 compared to 2017, primarily due to increases of (i) $8.9 million related to energy efficiency program costs previously offset by the related revenues prior to the adoption of ASU 2014-09, (ii) $3.3 million in outage costs at Rio Grande Unit 8, (iii) $2.4 million in transmission and distribution expense primarily due to increases in payroll costs and Palo Verde transmission expenses due to storm repairs, and (iv) $1.9 million in Four Corners operating expenses due to an adjustment in estimated pension and benefit costs and post-closing purchase price adjustments recorded in 2017. These increases were partially offset by a $2.9 million decrease in Palo Verde O&M expense primarily due to lower incentives and A&G benefits in 2018.
O&M expense increased $4.6 million, or 1.4%, in 2017 compared to 2016, primarily due to increases of (i) $7.1 million in maintenance outages at Newman Units 1, 3 and 4, (ii) $3.9 million in maintenance costs at Newman and MPS, (iii) $2.4 million in Palo Verde O&M expenses primarily due to higher A&G expenses, and (iv) $3.0 million in various other operating costs. These increases were partially offset by a decrease of $12.1 million in O&M costs in 2017 as a result of the sale of our interest in Four Corners in July 2016.
Depreciation and amortization expense
Depreciation and amortization expense increased $5.5 million, or 6.1%, in 2018 compared to 2017, primarily due to increases in plant, including distribution, general, Palo Verde and intangible plant.
Depreciation and amortization expense increased $6.5 million, or 7.7%, in 2017 compared to 2016, primarily due to increases in plant, including MPS Units 3 and 4, which were placed in service in May 2016 and September 2016, respectively. These increases were partially offset by the sale of the Company's interest in Four Corners in July 2016.
Taxes other than income taxes
Taxes other than income taxes increased $0.1 million, or 0.2%, in 2018 compared to 2017, primarily due to increased property tax rates and valuations, partially offset by decreased revenue related taxes in Texas.
Taxes other than income taxes increased $5.3 million, or 8.1%, in 2017 compared to 2016, primarily due to increased property tax rates and valuations in Texas as a result of MPS Units 3 and 4 being placed in service in 2016 and increased billed revenues in Texas.
Other income (deductions)
Other income (deductions) decreased $19.7 million, or 46.5%, in 2018 compared to 2017, primarily due to a $23.6 million increase in net realized and unrealized losses on securities held in the NDT. During the fourth quarter of 2018, the U.S. equity markets experienced the greatest overall fourth quarter declines since 2008. This decrease was partially offset by a $2.4 million increase in the expected return on benefit plan assets. Beginning on January 1, 2018, the Company adopted ASU 2016-01, Financial Instruments, and began recording unrealized gains and losses on equity securities held in the NDT directly in earnings. Further details are shown below (in thousands):
Other income (deductions) increased $0.5 million, or 1.2%, in 2017 compared to 2016, primarily due to a $3.0 million increase in net realized gains on securities held in the NDT. This increase was partially offset by a $4.0 million decrease in AEFUDC resulting from lower average balances of CWIP and a reduction in the Allowance for Equity Funds Used During Construction ("AEFUDC") rate.
Interest charges (credits)
Interest charges (credits) increased by $1.1 million, or 1.3%, in 2018 compared to 2017, primarily due to interest expense on the $125.0 million aggregate principal amount of 4.22% Senior Notes issued in June 2018 and due in August 2028, partially offset by (i) a net decrease in the interest cost component of net periodic benefit cost of the Company's employee benefit plans, (ii) increased allowance for borrowed funds used during construction ("ABFUDC") as a result of an increase in the ABFUDC rate and higher average balances of CWIP, and (iii) the redemption of $33.3 million of 2012 Series A 1.875% PCBs in 2017.
Interest charges (credits) increased by $4.1 million, or 5.1%, in 2017 compared to 2016, primarily due to decreased ABFUDC as a result of lower average balances of CWIP and a reduction in the ABFUDC rate and interest expense on the $150.0 million aggregate principal amount of 5.00% Senior Notes due 2044 issued in March 2016.
Income tax expense
Income tax expense decreased by $24.6 million, or 48.3%, in 2018 compared to 2017, primarily due to a decrease in the federal corporate income tax rate from 35% to 21% and a 25.8% reduction in pre-tax income, partially offset by a reduction in state tax reserves in 2017 due to the favorable settlement of Texas state income tax audits.
Income tax expense decreased by $2.9 million, or 5.4%, in 2017 compared to 2016, primarily due to favorable settlements of state income tax audits in Texas and Arizona.
New accounting standards adopted and to be adopted in the future
See Part II, Item 8, Financial Statements and Supplementary Data, Note B of Notes to Financial Statements for discussion on new accounting standards adopted and to be adopted in the future.
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
At December 31, 2018, our capital structure, including common stock, long-term debt, current maturities of long-term debt, and short-term borrowings under our RCF, consisted of 44.8% common stock equity and 55.2% debt. As of December 31, 2018, we had a balance of $12.9 million in cash and cash equivalents. Based on current projections, we believe that we will have adequate liquidity through our current cash balances, cash from operations, available borrowings under the RCF, and debt or equity issuances in the capital markets to meet all of our anticipated cash requirements over the next twelve months.
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, cash dividend payments, operating expenses including fuel costs, maintenance costs and taxes.
Capital Requirements. During the twelve months ended December 31, 2018, our capital requirements primarily consisted of expenditures for the construction and purchase of electric utility plant, payment of common stock dividends and purchases of nuclear fuel. Projected utility construction expenditures are to add new generation, expand and update our transmission and distribution systems, make capital improvements and replacements at Palo Verde and other generating facilities, and make investments in other property and equipment. Estimated cash construction expenditures for all capital projects for 2019 are expected to be approximately $249 million. See Part I, Item 1, "Business - Construction Program." Cash capital expenditures for new electric plant were $240.0 million in the twelve months ended December 31, 2018, compared to $199.9 million in the twelve months ended December 31, 2017. Capital requirements for purchases of nuclear fuel were $38.4 million for the twelve months ended December 31, 2018, as compared to $38.5 million for the twelve months ended December 31, 2017.
On December 28, 2018, we paid a quarterly cash dividend of $0.36 per share, or $14.6 million, to shareholders of record as of the close of business on December 14, 2018. We paid a total of $57.5 million in cash dividends during the twelve months ended December 31, 2018. On January 31, 2019, our Board of Directors declared a quarterly cash dividend of $0.36 per share payable on March 29, 2019, to shareholders of record as of the close of business on March 15, 2019. Typically, the Board of Directors reviews our dividend policy annually in the second quarter of each year. In addition, while we do not currently anticipate repurchasing shares of our common stock in 2019, we may repurchase shares of our common stock in the future. Under our repurchase 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, 2018. As of December 31, 2018, a total of 393,816 shares remain eligible for repurchase under the repurchase program.
We expect to continue to maintain a prudent level of liquidity and monitor market conditions for debt and equity securities. 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.
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. The following summary describes the major impacts of the TCJA on our liquidity.
The TCJA discontinued bonus depreciation for regulated utilities, which reduced tax deductions previously available to us for 2018 and 2019. The decrease in tax deductions results in the utilization of our net operating loss carryforwards ("NOL carryforwards") and other carryforwards approximately one year earlier than previously anticipated and is expected to result in higher income tax payments beginning in 2020, after the full utilization of NOL and other carryforwards. However, due to the lower federal corporate income tax rate enacted by the TCJA, our future federal corporate income tax payments will be made at the reduced rate of 21% beginning in 2018. Due to NOL and other carryforwards, minimal tax payments are expected for 2019, which are mostly related to state income taxes.
The effect of the TCJA on our rates is beneficial to our customers. Following the enactment of the TCJA and the reduction of the federal corporate income tax rate, revenues collected from our customers in 2018 were reduced by $28.2 million, which negatively impacted our cash flows and a comparable amount is expected during 2019.
We continually evaluate our funding requirements related to our retirement plans, other post-retirement benefit plans and decommissioning trust funds. We contributed $9.2 million and $9.8 million to our retirement plans during the twelve months ended
December 31, 2018, and 2017, respectively. We contributed $0.5 million to our other post-retirement benefit plans during both the twelve months ended December 31, 2018, and 2017. We contributed $2.1 million and $3.8 million to the NDT in 2018 and 2017, respectively. We are in compliance with the funding requirements of the federal government for our benefit plans. In addition, with respect to our nuclear plant decommissioning trust, we are in compliance with the funding requirements of the federal law and the ANPP Participation Agreement. We will continue to review our funding for these plans in order to meet our future obligations.
Capital Resources. Cash provided by operations, $285.4 million for the twelve months ended December 31, 2018, and $288.6 million for the twelve months ended December 31, 2017, is a significant source for funding capital requirements. A component of cash flows from operations is the change in net over-collection and under-collection of fuel revenues. Cash from operations has 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 full requirement customer. We recover actual fuel costs from customers through fuel adjustment mechanisms in Texas and New Mexico, and from our sales for resale full requirement 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. 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. We are required to request to refund fuel costs in any month when the over-recovery balance exceeds a threshold material amount and we expect fuel costs to continue to be materially over-recovered. We are permitted to seek to surcharge fuel under-recoveries in any month the balance exceeds a threshold material amount that we expect 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. On October 15, 2018, we filed a request with the PUCT to decrease our Texas fixed fuel factor by approximately 6.99% to reflect decreased fuel expenses primarily related to a decrease in the price of natural gas used to generate power. On October 25, 2018, our fixed fuel factor was approved on an interim basis effective for the first billing cycle of the November 2018 billing month. The revised factor was approved by the PUCT and the docket closed on November 19, 2018. The Texas fixed fuel factor will continue thereafter until changed by the PUCT. During the twelve months ended December 31, 2018, we had over-recoveries of fuel costs of $4.8 million compared to over-recoveries of fuel costs of $17.1 million during the twelve months ended December 31, 2017. At December 31, 2018, we had a net fuel over-recovery balance of $11.0 million, including over-recoveries of $8.9 million in Texas, $2.0 million in New Mexico, and $0.1 million in FERC jurisdictions.
We maintain the RCF for working capital and general corporate purposes and financing nuclear fuel through the RGRT. The RGRT, the trust through which we finance our portion of nuclear fuel for Palo Verde, is consolidated in our financial statements. The total amount borrowed for nuclear fuel by the RGRT, excluding debt issuance costs, was $136.2 million at December 31, 2018, of which $26.2 million had been borrowed under the RCF, and $110.0 million was borrowed through the issuance of senior notes. At December 31, 2017, the total amounts borrowed for nuclear fuel by the RGRT, excluding debt issuance costs, were $133.5 million, of which $88.5 million had been borrowed under the RCF and $45.0 million was borrowed through the issuance of senior notes. Interest costs on borrowings to finance nuclear fuel are accumulated by the RGRT and charged to us as fuel is consumed and recovered through fuel recovery charges. The outstanding balance under the RCF for working capital and general corporate purposes was $23.0 million at December 31, 2018, and $85.0 million at December 31, 2017. Total aggregate borrowings under the RCF as of December 31, 2018, were $49.2 million with an additional $300.7 million available to borrow.
We received approval from the NMPRC on October 7, 2015, to guarantee the issuance of up to $65.0 million of long-term debt by the RGRT to finance future purchases of nuclear fuel and to refinance existing nuclear fuel debt obligations. We received additional approval from the NMPRC on October 4, 2017, to amend and extend the RCF, issue up to $350.0 million in long-term debt and to redeem and refinance the $63.5 million 2009 Series A 7.25% PCBs and the $37.1 million 2009 Series B 7.25% PCBs, which are subject to optional redemption in 2019. The NMPRC approval to issue up to $350.0 million in long-term debt supersedes its prior approval. We received approval from the FERC on October 31, 2017, to issue up to $350.0 million in long-term debt, to guarantee the issuance of up to $65.0 million of long-term debt by the RGRT, and to continue to utilize our existing RCF with the ability to amend and extend the RCF at a future date, and to redeem, refinance and/or replace the 2009 Series A and Series B PCBs with debt of equal face value. The authorization approved by the FERC is effective from November 15, 2017 through November 14, 2019, and supersedes its prior approvals.
Under these authorizations, on June 28, 2018, we issued $125 million in aggregate principal amount of 4.22% Senior Notes due August 15, 2028, and guaranteed the issuance by the RGRT of $65 million in aggregate principal amount of 4.07% Senior Guaranteed Notes due August 15, 2025. The net proceeds from the sale of these senior notes were used to repay outstanding short-term borrowings under the RCF, which included borrowings made for working capital, general corporate purposes and the purchase of nuclear fuel. Also, under these authorizations, on September 13, 2018, we and RGRT entered into a third amended and restated credit agreement where we have available a $350.0 million RCF with a term ending on September 13, 2023. We may increase the RCF by up to $50.0 million (to a total of $400.0 million) during the term of the RCF, upon the satisfaction of certain conditions more fully set forth in the agreement, including obtaining commitments from lenders or third party financial institutions. In addition, we may extend the maturity date of the RCF up to two times, in each case for an additional one-year period, upon the satisfaction of certain conditions. Additionally, we are preparing for potential transactions related to the 2009 Series A and Series B PCBs. On
February 1, 2019, we purchased in lieu of redemption all of the 2009 Series A PCBs utilizing funds borrowed under the RCF. We are currently holding the bonds and may remarket them or replace them with debt instruments of equivalent value at a future date depending on our financing needs and market conditions, and in accordance with FERC action expected in March 2019 in response to our most recent FERC application (see below).
On January 30, 2019, we submitted applications with both the NMPRC and the FERC seeking approval to issue shares of common stock, including the reissuance of treasury shares, in an amount up to $200.0 million in one or more transactions. Included in the FERC application, we also requested various debt-related authorizations: approval to utilize the existing RCF for short-term borrowing not to exceed $400.0 million at any one time; to issue up to $225.0 million in new long-term debt; and to remarket the $63.5 million Series A PCBs and the $37.1 million Series B PCBs in the form of replacement bonds or senior notes of equivalent value, not to exceed $100.6 million. If approved, the FERC authorization would supersede its prior approvals.
Contractual Obligations. Our contractual obligations as of December 31, 2018 are as follows (in thousands):
_____________________
(1)
We have five outstanding issuances of senior notes. In May 2005, we issued $400.0 million aggregate principal amount of 6% Senior Notes due May 15, 2035. In June 2008, we issued $150.0 million aggregate principal amount of 7.5% Senior Notes due March 15, 2038. In December 2012, we issued $150.0 million aggregate principal amount of 3.3% Senior Notes due December 15, 2022. In December 2014, we issued $150.0 million aggregate principal amount of 5.0% Senior Notes due December 1, 2044. In March 2016, we issued an additional $150.0 million aggregate principal amount of 5.0% Senior Notes due December 1, 2044, for a total principal amount outstanding of 5.0% Senior Notes due December 1, 2044 of $300.0 million. In June 2018, we issued in a private placement offering $125.0 million aggregate principal amount of 4.22% Senior Notes due August 15, 2028.
(2)
We have three series of PCBs outstanding, two of which mature in 2040, and one of which matures in 2042. The 7.25% 2009 Series A and the 7.25% 2009 Series B PCBs with an aggregate principal amount, together, of $100.6 million have optional redemptions beginning in February 2019 and April 2019, respectively, at which time we expect to redeem, refinance or replace these bonds. On February 1, 2019, we purchased in lieu of redemption all of the 7.25% 2009 Series A with a principal amount of $63.5 million utilizing funds borrowed under the RCF. We are currently holding the bonds and may remarket them or replace them with debt instruments of equivalent value at a future date depending on our financing needs and market conditions.
(3)
In 2010, we and RGRT entered into a note purchase agreement pursuant to which the RGRT issued and sold $45.0 million aggregate principal amount of 5.04% RGRT Senior Notes, Series C, due August 15, 2020. In June 2018, we and RGRT entered into a note purchase agreement pursuant to which the RGRT issued and sold $65.0 million aggregate principal amount of 4.07% Senior Guaranteed Notes due August 15, 2025.
(4)
This reflects obligations outstanding under the $350.0 million RCF. At December 31, 2018, $23.0 million was borrowed for working capital and general corporate purposes and $26.2 million was borrowed by RGRT for nuclear fuel. This balance includes interest based on actual interest rates at the end of 2018 and assumes this amount will be outstanding for the entire year of 2019.
(5)
Amount is based on the minimum volumes per the contract and market and/or contract price at the end of 2018. 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 2018.
(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 post-retirement benefits for 2019. We have no minimum cash contractual funding requirement related to our retirement income plan or other post-retirement benefits for 2019. However, we are subject to minimum funding requirements of the Employee Retirement Income Security Act of 1974. We also may decide to fund at higher levels and expect to contribute $9.9 million to our retirement plans in 2019. Minimum
funding requirements for 2020 and beyond are not included due to the uncertainty of the applicable interest rates and the related return on assets.
(8)
This obligation is based on the decommissioning funding allowed in PUCT Docket No. 46831, effective July 18, 2017. We have no minimum funding obligation in the New Mexico jurisdiction effective July 1, 2016 with NMPRC Case No. 15-00127-UT. It is possible that our funding requirements could change based on the amounts allowed in future rate filings.
(9)
We lease land in El Paso, Texas, adjacent to Newman under a lease that expires in June 2033, subject to a renewal option of 25 years. We also have several other leases for office, parking facilities and equipment that 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 the RCF, which is based on floating rates.
To the extent the RCF is utilized for nuclear fuel purchases, interest rate risk, if any, related to the RCF is substantially mitigated through the operation of the PUCT and the 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.
The NDT consists 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 $134.2 million and $130.2 million as of December 31, 2018 and 2017, respectively. A hypothetical 10% increase in interest rates would reduce the fair values of the fixed income instruments by $1.7 million and $1.6 million at December 31, 2018 and 2017, respectively.
Equity Price Risk
The NDT includes marketable equity securities of approximately $135.9 million and $149.8 million at December 31, 2018 and 2017, respectively. A hypothetical 10% decrease in equity prices would have reduced the fair values of the equity securities by $13.6 million and $15.0 million based on their fair values at December 31, 2018 and 2017, respectively. Declines in market prices could require that additional amounts be contributed to the NDT to maintain minimum funding requirements. We do not expect to expend monies held in the NDT before 2044 or a later period when decommissioning of Palo Verde begins.
Commodity Price Risk
We utilize contracts of various durations for the purchase of natural gas and uranium concentrates 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, 2019, we had entered into forward sales and purchase contracts for energy as discussed in Part I, Item 1, "Business - Energy Sources - Purchased Power." These agreements are generally fixed-priced contracts that qualify for the "normal purchases and normal sales" exception provided in the 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 the 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, 2018. In making this assessment, the Company’s management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission's 2013 Internal Control - Integrated Framework. Based on its assessment, management believes that, as of December 31, 2018, 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 48 of the Annual Report on Form 10-K.
Item 8.
Item 8.Financial Statements and Supplementary Data
Report of Independent Registered Public Accounting Firm
To the Shareholders and Board of Directors
El Paso Electric Company:
Opinions on the Financial Statements and Internal Control over Financial Reporting
We have audited the accompanying balance sheets of El Paso Electric Company (the "Company") as of December 31, 2018 and 2017, and the related 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, 2018, and the related notes (collectively, the "financial statements"). We also have audited the Company’s internal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2018 and 2017, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2018, in conformity with U.S. generally accepted accounting principles. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.
Basis for Opinions
The Company’s management is responsible for these 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 the Company’s financial statements and an opinion on the Company’s internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) ("PCAOB") and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.
Our audits of the financial statements included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. 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.
Definition and Limitations of Internal Control over Financial Reporting
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.
/s/ KPMG LLP
We have served as the Company’s auditor since 1983.
Houston, Texas
February 28, 2019
EL PASO ELECTRIC COMPANY
BALANCE SHEETS
See accompanying notes to financial statements.
EL PASO ELECTRIC COMPANY
BALANCE SHEETS (Continued)
See accompanying notes to financial statements.
EL PASO ELECTRIC COMPANY
STATEMENTS OF OPERATIONS
(In thousands except for share data)
See accompanying notes to financial statements.
EL PASO ELECTRIC COMPANY
STATEMENTS OF COMPREHENSIVE OPERATIONS
(In thousands)
See accompanying notes to financial statements.
EL PASO ELECTRIC COMPANY
STATEMENTS OF CHANGES IN COMMON STOCK EQUITY
(In thousands except for share data)
See accompanying notes to financial statements.
EL PASO ELECTRIC COMPANY
STATEMENTS OF CASH FLOWS
(In thousands)
See accompanying notes to financial statements.
INDEX TO NOTES TO FINANCIAL STATEMENTS
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
A. Summary of Significant Accounting Policies
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.
Basis of Presentation. The Company maintains its accounts in accordance with the Uniform System of Accounts prescribed by the Federal Energy Regulatory Commission ("FERC").
Use of Estimates. The preparation of financial statements in conformity with United States ("U.S.") Generally Accepted Accounting Principles ("GAAP") 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. The Company evaluates its estimates on an on-going basis, including those related to depreciation, unbilled revenue, income taxes, fuel costs, pension and other post-retirement obligations and asset retirement obligations ("ARO"). Actual results could differ from those estimates.
Application of the Financial Accounting Standards Board ("FASB") Guidance for Regulated Operations. Regulated electric utilities typically prepare their financial statements in accordance with the FASB guidance for regulated operations. The 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 statements of operations. The FASB guidance for regulated operations also requires the Company to show certain 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 Part II, Item 8, Financial Statements and Supplementary Data, Note E of Notes to Financial Statements for further discussion. The Company applies the FASB guidance for regulated operations for all three of the jurisdictions in which it operates.
Comprehensive Income. Certain gains and losses that are not recognized currently in the statements of operations are reported as other comprehensive income in accordance with the 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 2018, 2017 and 2016 was 2.28%, 2.27% and 2.28%, 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, if applicable.
The cost of nuclear fuel is amortized to fuel expense on a units-of-production basis. The Company is also amortizing its share of costs associated with on-site spent fuel storage casks at Palo Verde Generating Station ("Palo Verde") over the burn period of the fuel that will necessitate the use of the storage casks. See Part II, Item 8, Financial Statements and Supplementary Data, Note F of Notes to Financial Statements for further discussion.
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.
Allowance for Funds Used During Construction ("AFUDC") and Capitalized Interest. The Company capitalizes interest (ABFUDC) and common equity (AEFUDC) costs to construction work in progress ("CWIP") and capitalizes interest to nuclear fuel in process in accordance with the FERC Uniform System of Accounts as provided for in the 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 semi-annual basis. The average AFUDC rates used in 2018, 2017 and 2016 were 5.95%, 5.38% and 6.43%, respectively.
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
Asset Retirement Obligation. The FASB guidance sets forth accounting requirements for the recognition and measurement of liabilities associated with the retirement of tangible long-lived assets. An ARO associated with long-lived assets included within the scope of the 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 Part II, Item 8, Financial Statements and Supplementary Data, Note G of Notes to Financial Statements for further discussion. Under the 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. Temporary cash investments with an original maturity of three months or less are considered cash equivalents. The Company's cash and cash equivalents do not include amounts held in trust by the Company's Palo Verde nuclear decommissioning trust funds ("NDT") or the pension and other post-retirement benefit trust funds.
Investments. The Company’s marketable securities, included in the NDT on the balance sheet, are reported at fair value and consist of cash, equity securities and debt securities held in the NDT. Investments in equity securities are measured at fair market value. Changes in fair value for equity securities are recognized in the statement of operations. Debt 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 the fair value of debt securities below original cost basis are determined to be other than temporary, the declines are reported as losses in the statements 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 Part II, Item 8, Financial Statements and Supplementary Data, Note P of Notes to Financial Statements for further discussion.
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 Part II, Item 8, Financial Statements and Supplementary Data, Note P of Notes to Financial Statements for further discussion.
Inventories. Inventories, primarily parts, materials, supplies, fuel oil and natural gas are stated at average cost, which is not to exceed recoverable cost.
Operating Revenues. The Company accrues revenues for services rendered, including unbilled electric service revenues. Fuel and purchase power expenses are stated at actual cost incurred. The Company recognizes revenue associated with contracts with customers when performance obligations under the terms of the contract with the customer are satisfied. Revenue is measured as the amount of consideration the Company receives in exchange for transferring goods or providing services to the customer. Taxes collected concurrently with revenue producing activities are excluded from revenue. Unbilled revenues are recorded for estimated amounts of energy delivered in the period following the customer's last billing cycle to the end of the reporting period. Unbilled revenues are estimated based on monthly generation volumes and by applying an average revenue/kilowatt-hour ("kWh") to the number of estimated kWhs delivered but not billed. Accounts receivable included accrued unbilled revenues of $21.6 million and $22.2 million as of December 31, 2018 and 2017, respectively. The Company presents revenues net of sales taxes in its statements of operations.
The Company’s Texas retail customers are billed under base rates and a fixed fuel factor approved by the Public Utility Commission of Texas ("PUCT"). The Company’s New Mexico retail customers are billed under base rates and a fuel adjustment clause that is adjusted monthly, as approved by the New Mexico Public Regulation Commission ("NMPRC"). The Company's FERC sales for resale customers are billed under formula base rates and fuel factors and a fuel adjustment clause that is adjusted monthly. The Company’s recovery of fuel and purchased power expenses is subject to periodic reconciliations of actual fuel and purchased power expenses incurred to actual fuel revenues collected. The difference between fuel and purchased power expenses incurred and fuel revenues charged to customers is reflected as over/under-collection of fuel revenues, which is included in regulatory liabilities/assets - current in the balance sheets. See Part II, Item 8, Financial Statements and Supplementary Data, Note D of Notes to Financial Statements for further discussion.
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
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
environment. Additions, deductions and balances for allowance for doubtful accounts for 2018, 2017 and 2016 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. The 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, unless those deferred taxes will be collected from or returned to customers in which case they are recorded as a regulatory asset or liability. See Part II, Item 8, Financial Statements and Supplementary Data, Note K of Notes to Financial Statements for further discussion. The Company recognizes tax assets and liabilities for uncertain tax positions in accordance with the recognition and measurement criteria of the FASB guidance for uncertainty in income taxes. See Part II, Item 8, Financial Statements and Supplementary Data, Note K of Notes to Financial Statements.
On December 22, 2017, the federal legislation commonly referred to as the Tax Cuts and Jobs Act of 2017 (“TCJA”) was enacted. Substantially all of the provisions of the TCJA are effective for taxable years beginning after December 31, 2017. The TCJA includes significant changes to the Internal Revenue Code of 1986 (as amended, the "IRC"), including amendments that significantly changed the taxation of business entities and includes specific provisions related to regulated public utilities. The more significant changes that impact the Company included in the TCJA are a reduction in the corporate federal income tax rate from 35% to 21%, elimination of the corporate alternative minimum tax provisions, additional limitations on deductions of executive compensation, and limiting the utilization of net operating losses ("NOL") arising after December 31, 2017 to 80% of taxable income with no carryback but with an indefinite carryforward. The specific provisions related to regulated public utilities in the TCJA generally provide for the continued deductibility of interest expense, the elimination of bonus depreciation for property acquired and placed into service after December 31, 2017 and the continuance of rate normalization requirements for accelerated depreciation benefits and changes to deferred tax balances as a result of the change in the corporate federal income tax rate.
The tax effects of changes in tax laws must be recognized in the period in which the law is enacted. GAAP also requires deferred tax assets and liabilities to be measured at the enacted tax rate expected to apply when temporary differences are to be realized or settled. Thus, at the date of enactment of the TCJA, the Company’s deferred taxes were re-measured based upon the new corporate federal income tax rate. The decrease in deferred taxes was recorded as a regulatory liability as it will be subject to refund to customers and is recorded at the expected cash flow to be reflected in future rates. See Part II, Item 8, Financial Statements and Supplementary Data, Note K of Notes to Financial Statements for further discussion.
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. 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
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
diluted earnings per share. See Part II, Item 8, Financial Statements and Supplementary Data, Note H of Notes to Financial Statements for further discussion.
Stock-Based Compensation. The Company has a stock-based long-term incentive plan. The Company is required under the 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 (requisite service period), which typically is the vesting period. Compensation cost is not recognized for anticipated forfeitures prior to vesting of equity instruments. See Part II, Item 8, Financial Statements and Supplementary Data, Note H of Notes to Financial Statements for further discussion.
Pension and Post-retirement Benefit Accounting. See Part II, Item 8, Financial Statements and Supplementary Data, Note N of Notes to Financial Statements for a discussion of the Company's accounting policies for its employee benefits.
Reclassification. Certain amounts in the financial statements for 2017 and 2016 have been reclassified to conform to the 2018 presentation. The Company implemented Accounting Standards Update ("ASU") 2017-07, Compensation - Retirement Benefits, and ASU 2016-15, Statement of Cash Flows, in the first quarter of 2018, retrospectively to all periods presented in the Company's financial statements. See Part II, Item 8, Financial Statements and Supplementary Data, Note B of Notes to Financial Statements for further discussion on the new accounting standards.
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
B. New Accounting Standards
New Accounting Standards Adopted
In March 2016, the FASB issued ASU 2016-09, Compensation - Stock Compensation (Topic 718) Improvements to Employee Share-Based Payment Accounting, to simplify the accounting for share-based payment transactions, including the income tax consequences, classification of awards either as equity or liabilities, and classification on the statements of cash flows. The Company adopted the new standard effective January 1, 2017. The adoption of the new standard did not have a material impact on the Company's financial condition, results of operations or cash flows. The cumulative effect of the adoption of the new standard was to increase net operating loss carryforward ("NOL carryforward") deferred tax assets and retained earnings by $0.2 million on January 1, 2017.
In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606), to provide a framework that replaced the prior revenue recognition guidance, and FASB has since modified the standard with several ASUs. The standard provides that an entity should recognize the amount of revenue to which it expects to be entitled for the transfer of promised goods or services to customers. On January 1, 2018, the Company adopted the new accounting standard using the modified retrospective method. There was no cumulative effect adjustment at the initial application of the new standard. In addition, comparative information has not been restated and continues to be reported under the accounting standards in effect for those periods. The Company expects the ongoing impact of the new standard to be immaterial to net income. Following the adoption of the standard, revenues of $8.9 million related to reimbursed costs of energy efficiency programs approved by the Company's regulators are reported in operating revenues from customers prospectively, as opposed to being offset with associated costs within operations and maintenance ("O&M") expenses. Related expenses of an equal amount are reported in O&M expenses. See Part II, Item 8, Financial Statements and Supplementary Data, Note C of Notes to Financial Statements for further discussion on revenues.
In January 2016, the FASB issued ASU 2016-01, Financial Instruments - Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities, to enhance the reporting model for financial instruments by addressing certain aspects of recognition, measurement, presentation and disclosure. The Company adopted the new standard effective January 1, 2018. The adoption of ASU 2016-01 eliminates the requirements to classify investments in equity securities with readily determinable fair values into trading or available for sale and requires entities to measure equity investments at fair value and recognize any changes in fair value in the Statements of Operations. ASU 2016-01 requires a modified retrospective approach and therefore comparative information has not been restated and continues to be reported under the accounting standards in effect for those periods. Upon adoption of the new standard, the Company recorded a cumulative effect adjustment, net of income taxes to increase retained earnings by $41.0 million with a corresponding decrease to accumulated other comprehensive income ("AOCI"). In addition, the Company recorded net losses of $18.6 million related to equity securities still held at December 31, 2018. In March 2018, the FASB issued ASU 2018-04, Investments - Debt Securities (Topic 320) and Regulated Operations (Topic 980), which provides clarification to ASU 2016-01.
In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows (Topic 230) Classification of Certain Cash Receipts and Cash Payments, to reduce diversity in practice in how certain cash receipts and cash payments are classified in the statement of cash flows. The Company adopted the new standard effective January 1, 2018. ASU 2016-15 was applied using a retrospective transition method to each period presented. Accordingly, the Company presented in the Statement of Cash Flows insurance proceeds received for equipment of $5.4 million, $9.6 million and $4.4 million, respectively, for the twelve months ended December 31, 2018, 2017 and 2016 as cash inflows from investing activities.
In March 2017, the FASB issued ASU 2017-07, Compensation - Retirement Benefits (Topic 715) Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost. ASU 2017-07 amends Accounting Standards Codification ("ASC") 715, Compensation - Retirement Benefits, to require companies to present the service cost component of net benefit cost in the income statement line items where compensation cost is reported. Companies will present all other components of net benefit cost separately from the line item(s) that includes the service cost and outside of any subtotal of operating income. In addition, only the service cost component will be eligible for capitalization in assets. The Company adopted the new standard effective January 1, 2018. The amendments in ASU 2017-07 were applied retrospectively for the income statement presentation of the service cost component and the other components of net benefit costs. The Company elected to apply the practical expedient and used the amounts disclosed in the pension and other postretirement benefit plan note for the 2017 and 2016 comparative periods as the estimation basis for applying the retrospective presentation requirements. See Part II, Item 8, Financial Statements and Supplementary Data, Note N of Notes to Financial Statements for further discussion on employee benefits.
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
In March 2018, the FASB issued ASU 2018-05, Income Taxes (Topic 740) Amendments to U.S. Securities and Exchange Commission ("SEC") Paragraphs Pursuant to SEC Staff Accounting Bulletin No. 118 ("SAB 118"), to add various SEC paragraphs for clarification due to the TCJA. The Company adopted ASU 2018-05 upon issuance and implemented SAB 118 in December of 2017 in conjunction with the enactment of the TCJA.
In August 2018, the FASB issued ASU 2018-15, Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract (Topic 350). ASU 2018-15 aligns the requirements for capitalizing implementation costs for a cloud computing arrangement with the requirements for capitalizing implementation costs for an internal use software license. Implementation costs for a cloud computing arrangement will be capitalized or expensed based on the nature of the costs and the project’s stage in which they are incurred by applying the existing guidance for internal use software implementation costs. Capitalized costs for a cloud computing arrangement will be presented on the same line of the balance sheet as any related prepaid amounts for the arrangement, while amortization of those costs will be presented on the same line of the income statement as the related hosting fees. Early adoption is permitted, and entities may apply the guidance either prospectively to eligible costs incurred on or after the effective date or retrospectively. The Company early-adopted this guidance in the third quarter of 2018, on a prospective basis, and the adoption did not have a material impact on the Company’s financial condition, results of operations or cash flows.
New Accounting Standards to be Adopted in the Future
In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842), to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and requiring qualitative and quantitative disclosures on leasing agreements. ASU 2016-02 maintains a distinction between finance leases and operating leases similar to the distinction under previous lease guidance for capital leases and operating leases. The impact of leases reported in the Company's operating results and statement of cash flows is expected to be similar to previous GAAP. ASU 2016-02 requires the recognition in the statement of financial position, by the lessee, of a liability to make lease payments (the lease liability) and a right-of-use asset representing its right to use the underlying asset for the lease term. How operating leases are recorded in regard to the Company's balance sheet represents a significant change from previous GAAP guidance. The lessee is permitted to make an accounting policy election to not recognize lease assets and lease liabilities for short-term leases. Adoption of the new lease accounting standard will require the Company to apply the new standard to the earliest period using a modified retrospective approach. As part of an effort to minimize adoption impact from the new standard, the FASB issued ASU 2018-01 and 2018-11. ASU 2018-01 provides an optional practical expedient to not evaluate existing or expired land easements under Topic 842, if those land easements were not previously accounted for as leases under ASC Topic 840, while ASU 2018-11 allows entities to adopt the standard with a cumulative effect adjustment as of the beginning of the adoption year, while maintaining prior year comparative financial information and disclosures as reported. As part of its application of ASU 2016-02, the Company has completed its analysis of its lease population and is finalizing the implementation of a new lease accounting system, as well as the evaluation of the impact on business processes, systems and controls to support recognition and disclosure under the new guidance. The Company anticipates it will elect the following practical expedients: the package of practical expedients outlined in ASU 2016-02, the land easement practical expedient outlined in ASU 2018-01, and the optional transition expedient outlined in ASU 2018-11. The Company also anticipates making the accounting policy election to not apply balance sheet recognition to short term leases. The Company will adopt this guidance effective January 1, 2019 and the adoption will only affect the balance sheet by recording lease obligations and corresponding right of use assets in an amount that ranges between $5.0 million and $8.0 million.
In June 2016, the FASB issued ASU 2016-13, Financial Instruments - Credit Losses (Topic 326). ASU 2016-13 changes how companies measure and recognize credit impairment for many financial assets. The new expected credit loss model will require companies to immediately recognize an estimate of credit losses expected to occur over the remaining life of the financial assets that are in the scope of the standard. The ASU also makes targeted amendments to the current impairment model for available-for-sale debt securities. ASU 2016-13 will be required for reporting periods beginning after December 15, 2019. ASU 2016-13 will be applied in a modified retrospective approach through a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is implemented. The Company is currently assessing the future impact of ASU 2016-13.
In February 2018, the FASB issued ASU 2018-02, Income Statement - Reporting Comprehensive Income (Topic 220), as a result of concerns raised due to the TCJA. More specifically, because the remeasurement of deferred taxes due to the change in the federal corporate income tax rate is required to be included in income from continuing operations, the tax effects of items within AOCI (referred to as stranded tax effects) do not reflect the appropriate tax rate. ASU 2018-02 generally allows companies to reclassify stranded taxes from AOCI to retained earnings. The amount of the adjustment would be the difference between the historical federal corporate income tax rate of 35% and the newly enacted 21% federal corporate income tax rate. The provisions
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of ASU 2018-02 are effective for fiscal years and interim periods within that reporting period beginning after December 15, 2018. Early adoption is permitted, including adoption in any interim periods for reporting periods for which financial statements have not been issued. The Company is currently evaluating the impact of ASU 2018-02 and its impact on regulated utilities. At December 31, 2018, stranded taxes in AOCI are approximately $7.2 million. The Company currently does not believe the adoption of this ASU will have a material impact on its financial condition, results of operations, or cash flows.
C. Revenues
On January 1, 2018, the Company adopted ASU 2014-09, Revenue from Contracts with Customers (Topic 606), for all of its contracts using the modified retrospective method. There was no cumulative effect adjustment at the initial application of the new standard. In addition, comparative information has not been restated and continues to be reported under the accounting standards in effect for those periods. The Company expects the ongoing impact of the new standard to be immaterial to net income and no significant changes in the Company's business processes and internal controls were necessary upon adoption of the new standard.
The following table disaggregates revenue from contracts with customers, for the twelve months ended December 31, 2018 (in thousands):
The Company recognizes revenue when performance obligations under the terms of the contract with the customer are satisfied. Revenue is measured as the amount of consideration the Company receives in exchange for transferring goods or providing services to the customer. Taxes collected concurrently with revenue producing activities are excluded from revenue. The Company has elected the optional invoice practical expedient for Wholesale and Wheeling revenues, as the invoice amount will correspond directly to the value provided by the Company's performance to date.
Retail. Retail contracts represent the Company's primary revenue source. The Company has determined that retail electric service to residential, commercial and industrial, and public authority customers represents an implied daily contract with the customer. The contract is comprised of an obligation to supply and distribute electricity and related capacity. Revenue is recognized, over time, equal to the product of the applicable tariff rates, as approved by the PUCT and the NMPRC, and the volume of the electricity delivered to the customer, or through the passage of time based upon providing the service of standing ready. Unbilled revenues are recognized at month end based on estimated monthly generation volumes and by applying an average revenue per kWh to the number of estimated kWhs delivered but not billed to customers, and recorded as a receivable for the period following the last billing cycle to the end of the reporting period. Retail customers receive a bill monthly, with payment due sixteen days after issuance.
Wholesale. Wholesale contracts primarily include forward power sales into markets outside the Company’s service territory when the Company has competitive generation capacity available, after meeting its regulated service obligations. Pricing is either fixed or based on an index rate with consideration potentially including variable components. Uncertainties regarding the variable consideration will be resolved when the transaction price is known at the point of delivering the energy. The obligation to deliver the electricity is satisfied over time as the customer receives and consumes the electricity. Wholesale customers are invoiced monthly on the 10th day of each month, with payment due by the 20th day of the month. In the case of the sale of renewable energy certificates, the transaction price is allocated to the performance obligation to deliver the confirmed quantity of the certificates based on the stand alone selling price of each certificate. Revenue is recognized as control of the certificates is transferred to the customer. The customer is invoiced upon the completed transfer of the certificates, with payment due within ten business days. Wholesale also includes an annual agreement between the Company and one of its wholesale customers, Rio Grande Electric
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Cooperative ("RGEC"), which involves the provision of full requirements electric service from the Company to RGEC. The rates for this service are recalculated annually and require FERC approval.
Wheeling (transmission). Wheeling involves the Company providing point-to-point transmission service, which includes the receipt of capacity and energy at designated point(s) and the transfer of such capacity and energy to designated point(s) of delivery on either a firm or non-firm basis for periods of one year or less. The performance obligation to provide capacity and transmit energy is satisfied over time as the Company performs. Transmission customers are invoiced on a monthly basis, with payment due within twenty days of receipt of the invoice.
Other. Other includes alternative revenue program revenue relating to the Company’s potential bonus awards from the PUCT and the NMPRC mandated energy efficiency programs. Both the PUCT and the NMPRC allow for the potential to earn an incentive bonus if the Company achieves its approved energy efficiency goals under the applicable programs. The Company recognizes revenue related to the energy efficiency program incentives at the point in time that the amount is objectively determinable generally based upon an approved order from the regulator, is probable of recovery, and if it is expected to be collected within 24 months. Other revenue also includes (i) late payment fees, (ii) leasing income, and (iii) the Company’s allocated share, based on ownership, of sales of surplus effluent water from Palo Verde.
Accounts receivable. Accounts receivable is principally comprised of revenue from contracts with customers. The Company recognizes expense for accounts that are deemed uncollectible in operating expense. The Company recognized $2.9 million of uncollectible expense for the twelve months ended December 31, 2018.
D. Regulation
General
The rates and services of the Company are regulated by incorporated municipalities in Texas, the PUCT, the NMPRC and the FERC. Municipal orders, ordinances and other agreements regarding rates and services adopted by Texas municipalities are subject to review and approval by the PUCT. The FERC has jurisdiction over the Company's wholesale (sales for resale - full requirement customer) transactions, transmission service and compliance with federally-mandated reliability standards. The decisions of the PUCT, the NMPRC and the FERC are subject to judicial review.
Texas Regulatory Matters
2015 Texas Retail Rate Case Filing. On August 10, 2015, the Company filed with the City of El Paso, other municipalities incorporated in its Texas service territory and the PUCT in the 2015 Texas Retail Rate Case, a request for an annual increase in non-fuel base revenues ("2015 Texas Retail Rate Case"). On July 21, 2016, the parties to PUCT Docket No. 44941 filed the Joint Motion to Implement Uncontested Amended and Restated Stipulation and Agreement which was unopposed by the parties. On August 25, 2016, the PUCT issued the PUCT Final Order in Docket No. 44941 ("2016 PUCT Final Order"). Interim rates associated with the annual non-fuel base rate increase became effective on April 1, 2016. The additional surcharges associated with the incremental Four Corners Generating Station ("Four Corners") costs, rate case expenses and the relate back of rates to consumption on and after January 12, 2016, through March 31, 2016, were implemented on October 1, 2016.
For financial reporting purposes, the Company deferred any recognition of the Company's request in its 2015 Texas Retail Rate Case until it received the 2016 PUCT Final Order on August 25, 2016. Accordingly, it reported in the third quarter of 2016 the cumulative effect of the 2016 PUCT Final Order, which related back to January 12, 2016.
2017 Texas Retail Rate Case Filing. On February 13, 2017, the Company filed with the City of El Paso, other municipalities incorporated in the Company's Texas service territory and the PUCT in the 2017 Texas Retail Rate Case, a request for an increase in non-fuel base revenues. On November 2, 2017, the Company filed the Joint Motion to Implement Uncontested Stipulation and Agreement with the Administrative Law Judges for the 2017 Texas Retail Rate Case.
On December 18, 2017, the PUCT issued the PUCT Final Order in Docket No. 46831 ("2017 PUCT Final Order"), which provides, among other things, for the following: (i) an annual non-fuel base rate increase of $14.5 million; (ii) a return on equity of 9.65%; (iii) all new plant in service as filed in the Company's rate filing package was prudent and used and useful and therefore is included in rate base; (iv) recovery of the costs of decommissioning Four Corners in the amount of $5.5 million over a seven
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year period beginning August 1, 2017; (v) the Company to recover reasonable rate case expenses of approximately $3.4 million through a separate surcharge over a three year period; and (vi) a requirement that the Company file a refund tariff if the federal statutory income tax rate, as it relates to the Company, is decreased before the Company files its next rate case. The 2017 PUCT Final Order also established baseline revenue requirements for recovery of future transmission and distribution investment costs (for which the Company could seek recovery after January 1, 2019) and includes a minimum monthly bill of $30.00 for new residential customers with distributed generation, such as private rooftop solar. Additionally, the 2017 PUCT Final Order allowed for the annual recovery of $2.1 million of nuclear decommissioning funding and establishes annual depreciation expense that is approximately $1.9 million lower than the annual amount requested by the Company in its initial filing. Finally, the 2017 PUCT Final Order allowed for the Company to recover revenues associated with the relate back of rates to consumption on and after July 18, 2017, through a separate surcharge, which expired on January 9, 2019, with a reconciliation of any over- or under-charge to be addressed in a separate proceeding.
New base rates, including additional surcharges associated with rate case expenses and the relate back of rates to consumption on and after July 18, 2017, through December 31, 2017, were implemented in January 2018.
For financial reporting purposes, the Company deferred any recognition of the Company's request in its 2017 Texas Retail Rate Case until it received the 2017 PUCT Final Order on December 18, 2017. Accordingly, it reported in the fourth quarter of 2017 the cumulative effect of the 2017 PUCT Final Order, which related back to July 18, 2017.
The 2017 PUCT Final Order required the Company to file a refund tariff if the federal statutory income tax rate, as it relates to the Company, was decreased before the Company files its next general rate case. Following the enactment of the TCJA on December 22, 2017, and in compliance with the 2017 PUCT Final Order, on March 1, 2018, the Company filed with the PUCT and each of its municipalities a proposed refund tariff designed to reduce base charges for Texas customers equivalent to the expected annual decrease of $22.7 million in federal income tax expense resulting from the TCJA changes, and an additional refund of $4.3 million for the amortization of a regulatory liability related to the reduced tax expense for the months of January through March of 2018. This filing was assigned PUCT Docket No. 48124. On March 27, 2018, the PUCT approved the Company's proposed refund tariff on an interim basis, subject to refund or surcharge, for customer billing effective April 1, 2018. Each of the Company's municipalities also implemented the Company's proposed tax credits on an interim basis effective April 1, 2018. The refund is reflected in rates over a period of one year beginning April 1, 2018, and will be updated annually until new base rates are implemented pursuant to the Company's next Texas rate case filing. The PUCT issued an order on December 10, 2018, approving the proposed refund tariff.
Texas Energy Efficiency Cost Recovery Factor. On May 1, 2017, the Company filed its annual application with the PUCT, which was assigned PUCT Docket No. 47125, to establish its energy efficiency cost recovery factor for 2018. In addition to projected energy efficiency costs for 2018 and a reconciliation of collections to prior year actual costs, the Company requested approval of an incentive bonus for the 2016 energy efficiency program results in accordance with PUCT rules. Interim rates were approved effective January 1, 2018. The Company, the PUCT Staff and the City of El Paso reached an agreement that includes an incentive bonus of $0.8 million. The agreement was filed on January 25, 2018, and was approved by the PUCT on February 15, 2018.
On May 1, 2018, the Company filed its annual application with the PUCT, which was assigned PUCT Docket No. 48332, to establish its energy efficiency cost recovery factor for 2019. In addition to projected energy efficiency costs for 2019 and a reconciliation of collections to actual costs for the prior year, the Company requested approval of a $1.0 million incentive bonus for the 2017 energy efficiency program results in accordance with PUCT rules. Instead of convening an actual hearing on the merits of this case, the parties agreed to enter into the record the pre-filed testimony of the parties and certain other exhibits and then file briefs on the contested issues. The Administrative Law Judge issued a proposed final decision on November 15, 2018, including the Company's fully requested incentive bonus. On January 17, 2019, the PUCT issued an order approving a modified bonus amount of $0.9 million.
Fuel and Purchased Power Costs. The Company's actual fuel costs, including purchased power energy costs, are recovered from customers through a fixed fuel factor. 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. 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
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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 periodic fuel reconciliation proceedings.
On November 30, 2016, the Company filed a request with the PUCT, which was assigned PUCT Docket No. 46610, to increase its fixed fuel factor by approximately 28.8% to reflect increased fuel expenses primarily related to an increase in the price of natural gas used to generate power. The increase in the fixed fuel factor was effective on an interim basis January 1, 2017, and approved by the PUCT on January 10, 2017.
On October 13, 2017, the Company filed a request with the PUCT, which was assigned PUCT Docket No. 47692, to decrease the Texas fixed fuel factor by approximately 19% to reflect decreased fuel expenses primarily related to a decrease in the price of natural gas used to generate power. The decrease in the Texas fixed fuel factor became effective beginning with the November 2017 billing month.
On April 13, 2018, the Company filed a request with the PUCT, which was assigned PUCT Docket No. 48264, to decrease the Texas fixed fuel factor by approximately 29% to reflect decreased fuel expenses primarily related to a decrease in the price of natural gas used to generate power. On April 25, 2018, the Company's proposed fuel factors were approved on an interim basis effective for the first billing cycle of the May 2018 billing month. The revised factor was approved by the PUCT and the docket closed on May 22, 2018.
On October 15, 2018, the Company filed a request with the PUCT, which was assigned PUCT Docket No. 48781, to decrease the Texas fixed fuel factor by approximately 6.99% to reflect decreased fuel expenses primarily related to a decrease in the price of natural gas used to generate power. On October 25, 2018, the Company's fixed fuel factor was approved on an interim basis effective for the first billing cycle of the November 2018 billing month. The revised factor was approved by the PUCT and the docket closed on November 19, 2018. The Texas fixed fuel factor will continue thereafter until changed by the PUCT. As of December 31, 2018, the Company had a net fuel over-recovery balance of approximately $8.9 million in Texas.
Fuel Reconciliation Proceeding. On September 27, 2016, the Company filed an application with the PUCT, designated as PUCT Docket No. 46308, to reconcile $436.6 million of Texas fuel and purchased power expenses incurred during the period of April 1, 2013, through March 31, 2016. On June 29, 2017, the PUCT approved a settlement in this proceeding. The settlement provides for the reconciliation of fuel and purchased power costs incurred from April 1, 2013, through March 31, 2016. The financial results for the twelve months ended December 31, 2017, includes a $5.0 million, pre-tax increase to income reflecting the settlement of the Texas fuel reconciliation proceeding. This amount represents Palo Verde performance rewards associated with the 2013 to 2015 performance periods net of disallowed fuel and purchased power costs as approved in the settlement. Additionally, the settlement modifies and tightens the Palo Verde performance rewards measurement bands beginning with the 2018 performance period. The April 1, 2016, through December 31, 2018, Texas jurisdictional fuel and purchased power costs subject to prudence review total approximately $353.4 million.
Community Solar. On June 8, 2015, the Company filed a petition with the PUCT to initiate a community solar program that includes the construction and ownership of a three-megawatt ("MW") solar photovoltaic system located at Montana Power Station ("MPS"). Participation is on a voluntary basis, and customers contract for a set capacity (kW) amount and receive all energy produced. This case was assigned PUCT Docket No. 44800. The Company filed a settlement agreement among all parties on July 1, 2016, approving the program, and the PUCT approved the settlement agreement and program on September 1, 2016. On April 19, 2017, the Company announced that the entire three-MW program was fully subscribed by approximately 1,500 Texas customers. The Community Solar facility began commercial operation on May 31, 2017.
On March 20, 2018, the Company filed a petition with the PUCT and each of its Texas municipalities to expand its community solar program in Texas to include two-MW of solar powered generation from the ten-MW solar photovoltaic facility located at Newman Power Station ("Newman") and to reduce rates under the community solar tariff. The case before the PUCT was assigned PUCT Docket No. 48181 and a hearing was held on December 4, 2018. The Company cannot predict the outcome of the case at this time.
Transmission Cost Recovery Factor. On January 25, 2019, the Company filed an application with the PUCT to establish its Transmission Cost Recovery Factor ("TCRF"), which was assigned PUCT Docket No. 49148 ("2019 TCRF rate filing"). The 2019 TCRF rate filing is designed to recover a requested $8.2 million of Texas jurisdictional transmission revenue requirement that is not currently being recovered in the Company's Texas base rates for transmission-related investments placed in service from October 1, 2016, through September 30, 2018, net of retirements. The Company cannot predict the outcome of this filing at this time.
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Four Corners Generating Station. On February 17, 2015, the Company and Arizona Public Service Company ("APS") entered into an asset purchase agreement ("Purchase and Sale Agreement") providing for the sale of the Company's interest in Four Corners to APS. The sale of the Company's interest in Four Corners closed on July 6, 2016. See Part II, Item 8, Financial Statements and Supplementary Data, Note F of Notes to Financial Statements for further discussion on the sale of Four Corners.
On June 10, 2015, the Company filed an application in Texas requesting reasonableness and public interest findings and certain rate and accounting findings related to the Purchase and Sale Agreement. This case was assigned PUCT Docket No. 44805. Subsequent to the filing of the application, the case was subject to numerous procedural matters, including a March 23, 2016, order in which the PUCT determined not to dismiss the reasonableness and public interest issues in this docket but to consider the requested rate and accounting findings, including coal mine reclamation costs, in a rate case proceeding. On September 1, 2016, a motion by parties in the proceeding to suspend the procedural schedule in order to pursue settlement was approved. On March 3, 2017, the Company filed a Joint Motion to Implement Stipulation and Agreement ("Stipulation and Agreement"), and PUCT Staff filed its recommendation that the Company’s disposition of its interest in Four Corners was reasonable and consistent with the public interest. Additionally, the signatories of the Stipulation and Agreement agreed to support the recovery of the Company's Four Corners decommissioning costs in the 2017 Texas Retail Rate Case. A final order approving the Stipulation and Agreement was adopted by the PUCT on March 30, 2017. The approval to recover Four Corners decommissioning costs was included in the 2017 PUCT Final Order.
Other Required Approvals. The Company has obtained other required approvals for tariffs and other approvals required by the Texas Public Utility Regulatory Act ("PURA") and the PUCT.
New Mexico Regulatory Matters
2015 New Mexico Rate Case Filing. On May 11, 2015, the Company filed a request with the NMPRC, in Case No. 15-00127-UT, for an annual increase in non-fuel base rates. On June 8, 2016, the NMPRC issued its final order in Case No. 15-00127-UT ("NMPRC Final Order"), which approved an annual increase in non-fuel base rates of approximately $0.6 million, an increase of approximately $0.5 million in other service fees and a decrease in the Company's allowed return on equity to 9.48%. The NMPRC Final Order concluded that all of the Company's then-new plant in service was reasonable and necessary and therefore would be recoverable in rates. The Company's rates were approved by the NMPRC effective July 1, 2016, and implemented at such time.
Future New Mexico Rate Case Filing. On April 12, 2017, the NMPRC issued an order in Case No. 15-00109-UT requiring the Company to make a rate filing in New Mexico no later than July 31, 2019, using an appropriate historical test year period.
New Mexico Order Commencing Review of the Effects of the TCJA on Regulated New Mexico Utilities. On January 24, 2018, the NMPRC initiated a proceeding in Case No. 18-00016-UT on the impact of the TCJA on New Mexico regulated utilities. On February 23, 2018, the Company responded to a NMPRC Staff inquiry regarding the proceeding. On April 4, 2018, the NMPRC issued an order requiring the Company to file a proposed interim rate rider to adjust the Company's New Mexico base revenues in amounts equivalent to the Company's reduced income tax expense for New Mexico customers resulting from the TCJA, to be implemented on or before May 1, 2018. The NMPRC order further requires that the Company record and track a regulatory liability for the excess accumulated deferred income taxes created by the change in the federal corporate income tax rate, consistent with the effective date of the TCJA, and subject to amortization determined by the NMPRC in the Company's next general rate case. The Company recorded such a regulatory liability during the quarter ended December 31, 2017. On April 16, 2018, after consultation with the New Mexico Attorney General pursuant to the NMPRC order, the Company filed an interim rate rider with the NMPRC with a proposed effective date of May 1, 2018. The annualized credits expected to be refunded to New Mexico customers approximate $4.9 million. The Company implemented the interim rate rider in customer bills beginning May 1, 2018 pursuant to the NMPRC order.
On September 5, 2018, the NMPRC issued an order in Case No. 17-00255-UT involving Southwestern Public Service Company's ("SPS's") request to change rates in which the NMPRC directed SPS to refund the difference in corporate tax rate from January 1, 2018, through the effective date of new rates. SPS appealed the NMPRC order to the New Mexico Supreme Court in Southwestern Public Service Co. v. NMPRC, No. S-1-SC-37248 ("SPS Appeal No. 1"), challenging the refund as prohibited retroactive ratemaking among other reasons. The New Mexico Supreme Court issued a partial and interim stay of the rates on September 26, 2018. On September 12, 2018, the NMPRC in Case No. 18-00016-UT issued an Order Regarding the Disposition of Tax Savings Under the Federal Tax Cuts and Jobs Act of 2017, which put public utilities on notice that all revenue collected through general rates for the purpose of payment of federal income taxes is and will continue to be subject to possible refund upon a subsequent determination to be made in the appropriate pending or future NMPRC adjudicatory hearing. On October 11, 2018, SPS filed a Notice of Appeal of that NMPRC order to the New Mexico Supreme Court in Southwestern Public Service Co. v.
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NMPRC, No. S-1-SC-37308 ("SPS Appeal No. 2"). Opening briefs in SPS Appeal No. 1 were filed January 14, 2019. In the event the NMPRC order in Case No. 17-00255-UT is upheld by the New Mexico Supreme Court, the Company would likely be required to record and refund approximately $1.2 million to its New Mexico customers, which represents tax benefits received by the Company for the period January 1, 2018, through April 30, 2018. On February 15, 2019, the NMPRC and SPS filed a joint motion for remand and stipulated dismissal of SPS appeals of NMPRC orders with the New Mexico Supreme Court, which among other things, reflects agreements between the NMPRC and SPS, which in part provide, that the NMPRC will replace the order in Case No. 17-00255-UT with a new order that eliminates the retroactive TCJA refund and that SPS will dismiss Appeals No. 1 and No. 2. The Company is monitoring the SPS cases and cannot determine the outcome of the cases at this time.
Fuel and Purchased Power Costs. Historically, fuel and purchased power costs were recovered through base rates and a Fuel and Purchased Power Cost Adjustment Clause ("FPPCAC") that accounts for changes in the costs of fuel relative to the amount included in base rates. Effective July 1, 2016, with the implementation of the NMPRC Final Order, fuel and purchased power costs are no longer recovered through base rates but are recovered through the FPPCAC. The Company's request to reconcile its fuel and purchased power costs for the period January 1, 2013, through December 31, 2014, also was approved in the NMPRC Final Order. New Mexico jurisdictional costs subject to prudence review are costs from January 1, 2015, through December 31, 2018, that total approximately $206.8 million. At December 31, 2018, the Company had a net fuel over-recovery balance of approximately $0.4 million related to the FPPCAC in New Mexico. As required, the Company filed a request to continue use of its FPPCAC with the NMPRC on January 5, 2018, which was assigned Case No. 18-00006-UT. The NMPRC issued a final order in the case on February 13, 2019, which authorized the Company to continue use of its FPPCAC without change and approved the Company's reconciliation of its fuel and purchased power costs for the period January 1, 2015, through December 31, 2016. The final order is subject to rehearing and appeal for thirty days after the February 13, 2019 date of issuance. The Company cannot predict the outcome of this case at this time.
Effective January 1, 2018, pursuant to the final order in NMPRC Case No. 17-00090-UT, the Renewable Portfolio Standard ("RPS") costs for New Mexico are recovered through a separate RPS Cost Rider and not through the FPPCAC. At December 31, 2018, the Company had a net fuel over-recovery balance related to the RPS Cost Rider of approximately $1.6 million. The RPS Cost Rider is updated in an annual NMPRC filing, including a reconciliation of the prior calendar year’s RPS costs and RPS Cost Rider revenue.
5-MW Holloman Air Force Base ("HAFB") Facility Certificate of Convenience and Necessity ("CCN"). On October 7, 2015, in Case No. 15-00185-UT, the NMPRC issued a final order approving a CCN for a five-MW solar power generation facility located on HAFB in the Company's service territory in New Mexico. The Company and HAFB negotiated a retail contract, which includes a power sales agreement for the facility, to replace the existing load retention agreement that was approved by NMPRC final order issued October 5, 2016, in Case No. 16-00224-UT. The solar generation facility began commercial operation on October 18, 2018.
New Mexico Efficient Use of Energy Recovery Factor. On July 1, 2016, the Company filed its annual application with the NMPRC requesting approval of its 2017 Energy Efficiency and Load Management Plan and to establish the Efficient Use of Energy recovery factor ("EUERF") for 2017. In addition to projected energy efficiency costs for 2017, the Company requested approval of a $0.4 million incentive for 2017 energy efficiency programs in accordance with NMPRC rules. This application was assigned Case No. 16-00185-UT. On February 22, 2017, the NMPRC issued a final order approving the Company’s 2017 Energy Efficiency and Load Management Plan. The Company’s EUERF was approved and effective in customer bills beginning on March 1, 2017. NMPRC rules authorize continuation of the energy efficiency programs and incentive approved in Case No. 16-00185-UT through 2018. The Company recorded approved incentives in operating revenues of $0.3 million and $0.7 million in 2018 and 2017, respectively, related to its 2015 through 2017 Energy Efficiency and Load Management Plans.
On July 2, 2018, the Company filed its required application with the NMPRC for approval of its 2019-2021 Energy Efficiency and Load Management Plan and EUERF. The application includes a request for a base incentive of 7.1% of program expenditures, or approximately $0.4 million annually for 2019-2021. The application was assigned Case No. 18-00116-UT and hearings were held on November 7, 2018, and November 8, 2018. The Hearing Examiner issued a Recommended Decision on January 30, 2019, and a final order from the NMPRC is pending. The Company cannot predict the outcome of this case at this time.
Community Solar. On April 24, 2018, the Company filed an application with the NMPRC to initiate a community solar program in New Mexico to include construction and ownership of a two-MW solar photovoltaic system located in Doña Ana County near the City of Las Cruces. Customer participation would have been on a voluntary basis, and customers would have contracted for a set capacity (kW) amount and would have received all energy produced by their subscribed capacity. The application was assigned Case No. 18-00099-UT and was dismissed without prejudice on October 31, 2018. The NMPRC set aside its October 31, 2018, order dismissing the application without prejudice, and on December 19, 2018, the NMPRC issued an Order Requiring
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El Paso Electric Company to Conduct Request for Proposals and to Amend Application; Order Extending Statutory Period and Appointing Hearing Examiner that would have required the Company to amend its initially-filed application on or before February 15, 2019. However, on January 10, 2019, the NMPRC (with three new Commissioners) reconsidered its prior order and dismissed the Community Solar application without prejudice. The case is now closed.
Integrated Resource Plan. On September 17, 2018, the Company filed its Integrated Resource Plan with the NMPRC for the period 2018-2037 ("2018 IRP") in Case No. 18-00293-UT as required by regulation and the Joint Stipulation in NMPRC Case No. 15-00241-UT, which was the Company's prior integrated resource plan filing. The triennial filing requires a public advisory process as part of the development of the plan to identify a cost-effective portfolio of resources. The filed plan is subject to written public comments filed with the NMPRC to which the Company responded on October 29, 2018. NMPRC Staff filed a written report on November 16, 2018, recommending that the NMPRC return the 2018 IRP to the Company with instructions for re-filing to correct 12 deficiencies identified by the NMPRC Staff report. On December 5, 2018, the NMPRC issued an Order Partially Accepting Integrated Resource Plan; Order Requiring Refiling for Deficiencies. Pursuant to that order, on January 3, 2019, the Company filed an amended 2018 IRP. On January 10, 2019, in light of a pending motion for reconsideration, the NMPRC ordered its Staff to provide additional information and respond to issues raised regarding the filed 2018 IRP. The Company cannot predict the outcome of the NMPRC's review of the plan or the outcome of this case at this time.
Issuance of Long-Term Debt, Securities Financing, and Guarantee of Debt. On October 7, 2015, the Company received approval in NMPRC Case No. 15-00280-UT to guarantee the issuance of up to $65.0 million of long-term debt by the Rio Grande Resources Trust II ("RGRT") to finance future purchases of nuclear fuel and to refinance existing nuclear fuel debt obligations, which remains effective. Under this authorization, on June 28, 2018, the RGRT issued $65.0 million in aggregate principal amount of 4.07% Senior Guaranteed Notes due August 15, 2025. On October 4, 2017, the Company received additional approval in NMPRC Case No. 17-00217-UT to amend and extend the Company's Revolving Credit Facility ("RCF"), issue up to $350.0 million in long-term debt and to redeem and refinance the $63.5 million 2009 Series A 7.25% Pollution Control Bonds ("PCBs") and the $37.1 million 2009 Series B 7.25% PCBs, which have optional redemptions beginning in 2019. The NMPRC approval to issue $350.0 million in long-term debt supersedes its prior approval. Under this authorization, on June 28, 2018, the Company issued $125.0 million in aggregate principal amount of the Company's 4.22% Senior Notes due August 15, 2028. Additionally, on September 13, 2018, the Company and the Bank of New York Mellon Trust Company, N.A., as trustee of the RGRT, entered into a $350.0 million third amended and restated credit agreement. See Part II, Item 8, Financial Statements and Supplementary Data, Note J of Notes to Financial Statements for further discussion on long-term debt and financing obligations.
On January 30, 2019, the Company submitted an application with the NMPRC seeking approval to issue shares of common stock, including the reissuance of treasury shares, in an amount up to $200.0 million in one or more transactions. The application was assigned Case No. 19-00033-UT, and a hearing is scheduled for March 15, 2019. Additionally, the Company is preparing for potential transactions related to the 2009 Series A and Series B PCBs. On February 1, 2019, the Company purchased in lieu of redemption all the $63.5 million 2009 Series A 7.25% PCBs. The bonds were purchased utilizing funds borrowed under the RCF. The Company is currently holding the bonds and may remarket them or replace them with debt instruments of equivalent value at a future date depending on the Company's financing needs and market conditions.
Other Required Approvals. The Company has obtained other required approvals for tariffs and other approvals as required by the New Mexico Public Utility Act and the NMPRC.
Federal Regulatory Matters
Inquiry Regarding the Effect of the TCJA on Commission-Jurisdictional Rates and Order to Show Cause. On March 15, 2018, the FERC issued two show cause orders under Section 206 of the Federal Power Act and Rule 209(a) of the FERC’s Rules of Practice and Procedure, directing 48 individual public utilities with stated transmission rates or transmission formula rates with a fixed line item of 35% for the federal income tax component to, within 60 days of the date of the orders, either (1) propose revisions to their transmission rates under their open access transmission tariffs or transmission owner tariffs on file with the FERC, or (2) show cause why they should not be required to do so ("Show Cause Proceeding"). The Company was included in the list of public utilities impacted by the FERC orders. On May 14, 2018, the Company submitted its response, as required by the FERC order, which demonstrated that the reduced annual income tax does not cause the Company's total transmission revenues to become excessive and therefore no rate reduction was justified. Instead, the Company stated in its response that it will prepare for a future filing in which it will seek approval for revised Open Access Transmission Tariff ("OATT") rates that would include the recovery of an increased total transmission revenue requirement from OATT customers based on current circumstances and appropriate forward-looking adjustments. On November 15, 2018, FERC issued an order finding that the Company had demonstrated that no
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NOTES TO FINANCIAL STATEMENTS
rate reduction was justified and terminating the Show Cause Proceeding. The Company expects to file its request for approval to revise OATT rates in the third quarter of 2019.
Notice of Proposed Rulemaking on Public Utility Transmission Changes to Address Accumulated Deferred Income Taxes. On November 15, 2018, the FERC issued a Notice of Proposed Rulemaking ("NOPR") that proposes to direct public utilities with transmission OATT rates, a transmission owner tariff or a rate schedule to determine the amount of excess or deficient accumulated deferred income taxes caused by the TCJA’s reduction to the federal corporate income tax rate and return or recover this amount to or from customers. The NOPR has been assigned FERC Docket No. RM19-5-000. The Company is currently evaluating the impact of this proposed rulemaking.
Issuance of Long-Term Debt, Securities Financing, and Guarantee of Debt. On October 31, 2017, the FERC issued an order in Docket No. ES17-54-000 approving the Company’s filing to (i) amend and extend the RCF; (ii) issue up to $350.0 million in long-term debt; (iii) guarantee the issuance of up to $65.0 million of long-term debt by the RGRT; and (iv) redeem, refinance and/or replace the $63.5 million 2009 Series A 7.25% PCBs and the $37.1 million 2009 Series B 7.25% PCBs, which have optional redemptions beginning in 2019. The order also approved the Company's request to continue to utilize the existing RCF with the ability to amend and extend at a future date. The authorization is effective from November 15, 2017, through November 14, 2019, and supersedes prior FERC approvals. Under this authorization, on June 28, 2018, the Company issued $125.0 million in aggregate principal amount of the Company's 4.22% Senior Notes due August 15, 2028, and the RGRT issued $65.0 million in aggregate principal amount of its 4.07% Senior Guaranteed Notes due August 15, 2025. Also, on September 13, 2018, the Company and the Bank of New York Mellon Trust Company, N.A., as trustee of the RGRT, entered into a $350.0 million third amended and restated credit agreement. Additionally, the Company is preparing for potential transactions related to the 2009 Series A and Series B PCBs. On February 1, 2019, the Company purchased in lieu of redemption all the $63.5 million 2009 Series A 7.25% PCBs. The bonds were purchased utilizing funds borrowed under the RCF. The Company is currently holding the bonds and may remarket them or replace them with debt instruments of equivalent value at a future date depending on the Company's financing needs and market conditions and in accordance with FERC action expected in March 2019 in response to the Company’s most recent FERC application (see below). See Part II, Item 8, Financial Statements and Supplementary Data, Note J of Notes to Financial Statements for further discussion on long-term debt and financing obligations.
On January 30, 2019, the Company submitted an application with the FERC seeking approval to issue shares of common stock, including the reissuance of treasury shares, in an amount up to $200.0 million in one or more transactions. Included in the FERC application, the Company also requested various debt-related authorizations: approval to utilize the existing RCF for short-term borrowing not to exceed $400.0 million at any one time; to issue up to $225.0 million in new long-term debt; and to remarket the $63.5 million 2009 Series A 7.25% PCBs and the $37.1 million 2009 Series B 7.25% PCBs in the form of replacement bonds or senior notes of equivalent value, not to exceed $100.6 million. If approved, the FERC authorization would supersede its prior approvals.
Other Required Approvals. The Company has obtained required approvals for rates, tariffs and other approvals as required by the Federal Power Act and the FERC.
U.S. Department of Energy ("DOE"). The DOE regulates the Company's exports of power to Mexico pursuant to a DOE grant of export authorization. In addition, the Company is the holder of two presidential permits issued by the DOE under which the Company constructed and operates border facilities crossing the U.S./Mexico border.
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 Part II, Item 8, Financial Statements and Supplementary Data, Note F of Notes to Financial Statements for further discussion of spent fuel storage and disposal costs.
Sales for Resale and Network Transmission Service to Rio Grande Electric Cooperative
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 the RGEC pursuant to the Company's 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 the RGEC. The Company's service to RGEC is regulated by FERC.
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NOTES TO FINANCIAL STATEMENTS
E. 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 balance sheet are presented below (in thousands):
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(a)
This item relates to (i) the regulatory treatment of the equity portion of AFUDC which is recovered in rate base by an offset with the related accumulated deferred income tax liability, and (ii) excess deferred state income taxes which are recovered through amortization to tax expense in cost of service. The amortization period for the excess deferred state income taxes is 15 years as established in the 2016 PUCT Final Order and the NMPRC Final Order.
(b)
This item is recovered as a component of the weighted cost of debt and amortized over the life of the related debt issuance.
(c)
This item relates to coal reclamation costs associated with Four Corners. The Texas portion was approved for recovery in PUCT Docket No. 46308 and will be recovered over seven years through June 2023. The New Mexico amortization period will be established in the next general rate case.
(d)
This item relates to the decommissioning of Four Corners. The Texas portion was approved for recovery in PUCT Docket No. 46308 and will be recovered over seven years through July 2024. The New Mexico amortization period will be established in the next general rate case.
(e)
This item is recovered through fuel recovery mechanisms established by tariffs.
(f)
The 2017 PUCT Final Order approved a new recovery period for these costs, beginning January 10, 2018.
(g)
This item relates to the recovery of revenues through two separate surcharges; one for the 2015 Texas Retail Rate Case relate back revenues beginning October 1, 2016, and ending September 30, 2017, and a second surcharge for the 2017 Texas Retail
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NOTES TO FINANCIAL STATEMENTS
Rate Case relate back revenues beginning January 10, 2018, and ending January 9, 2019. Amounts over-recovered through these surcharges will be addressed in the next Texas fuel reconciliation. See Part II, Item 8, Financial Statements and Supplementary Data, Note D of Notes to Financial Statements for further discussion.
(h)
This item relates to renewable energy credits and procurement plan costs, of which a component has been approved for recovery in the NMPRC Final Order. The remaining balance will be requested for recovery in the next general rate case.
(i)
The amortization period for this item is based upon the U.S. Nuclear Regulatory Commission ("NRC") license life for each unit at Palo Verde.
(j)
This item primarily relates to the reduction in the federal corporate income tax rate from 35% to 21% as enacted by the TCJA. The amortization period for the recovery on this item will be addressed in the next base rate filings in all jurisdictions. See Part II, Item 8, Financial Statements and Supplementary Data, Note K of Notes to Financial Statements for further discussion.
(k)
The amortization period is based upon the life of the associated assets.
(l)
This item is recovered or credited through a recovery factor that is set annually.
(m)
This item represents the net over-recovery of fuel and purchased power expense which is refunded to customers through fuel rates.
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NOTES TO FINANCIAL STATEMENTS
F. 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, 2018 (in thousands):
The Company owns a 15.8% interest in each of the three nuclear generating units and common facilities ("Common Facilities") at Palo Verde, in Wintersburg, Arizona. The Palo Verde Participants include the Company and six other utilities: APS, Southern California Edison Company, Public Service Company of New Mexico, Southern California Public Power Authority, Salt River Project Agricultural Improvement and Power District and the Los Angeles Department of Water and Power.
A summary of the Company’s investment in jointly-owned utility plant, excluding fuel inventories, at December 31, 2018 and 2017 is as follows (in thousands):
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(a) Includes three jointly-owned transmission lines.
Amortization of intangible plant (software) is provided on a straight-line basis over the estimated useful life of the asset (ranging from 3 to 15 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):
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NOTES TO FINANCIAL STATEMENTS
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 dated August 23, 1973, as amended ("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, O&M expense, and capital costs. The Company’s share of direct expenses in Palo Verde and other jointly-owned utility plants is reflected in fuel expense, O&M expense, miscellaneous other deductions, and taxes other than income taxes in the Company’s 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.
Nuclear Regulatory Commission. The NRC regulates the operation of all commercial nuclear power reactors in the U.S., 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.
Palo Verde Operating Licenses. Operation of each of the three Palo Verde Units requires an operating license from the NRC. The NRC issued full power operating licenses for Unit 1 in June 1985, Unit 2 in April 1986 and Unit 3 in November 1987 and issued renewed operating licenses for each of the three units in April 2011, which extended the licenses for Units 1, 2 and 3 to June 2045, April 2046 and November 2047, respectively.
Decommissioning. Pursuant to the ANPP Participation Agreement and federal law, the Company funds 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 the NDT 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, 2018, the NDT had a balance of $276.9 million, which is above its minimum funding level. The Company monitors the status of the NDT and adjusts contributions accordingly.
Decommissioning costs are estimated every three years based upon engineering cost studies performed by outside engineers retained by APS. In April 2017, the Palo Verde Participants approved the 2016 Palo Verde decommissioning study (“2016 Study”). The 2016 Study estimated that the Company must fund approximately $432.8 million (stated in 2016 dollars) to cover its share of decommissioning costs which was an increase in decommissioning costs of $52.1 million (stated in 2016 dollars) from the 2013 Palo Verde decommissioning study ("2013 Study"). The effect of this change increased the ARO by $3.5 million, which was recorded during the second quarter of 2017, and increased annual expenses starting in April 2017. Although the 2016 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 uncertainty. As provided in the ANPP Participation Agreement, the participants are required to conduct a new decommissioning study every three years. While the Company attempts to seek amounts in rates to meet its decommissioning obligations, it is not able to conclude given the evidence available to it now that it is probable these costs will continue to be collected over the period until decommissioning begins in 2044. The Company is ultimately responsible for these costs and its future actions combined with future decisions from regulators will determine how successful the Company is in this effort.
Spent Fuel and Waste Disposal. Pursuant to the Nuclear Waste Policy Act of 1982, as amended in 1987, 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 by 1998. The DOE's obligations are reflected in a contract for Disposal of Spent Nuclear Fuel and/or High-Level Radioactive Waste with each nuclear power plant. The DOE failed to begin accepting spent nuclear fuel by 1998. On December 19, 2012, APS, acting on behalf of itself and the Palo Verde Participants, filed a second breach of contract lawsuit against the DOE. This lawsuit sought to recover damages incurred due to the DOE’s failure to accept Palo Verde’s spent nuclear fuel for the period beginning January 1, 2007 through June 30, 2011. Pursuant to the terms of the August 18, 2014 settlement agreement, and as amended with the DOE, APS files annual claims for the period July 1 of the then-previous year to June 30 of the then-current year on behalf of itself and those utilities that share in power and energy entitlements, and bear certain allocated costs, with respect to Palo Verde based upon the ANPP Participation Agreement dated August 23, 1973. The settlement agreement, as amended, provides APS with a method for submitting claims and receiving recovery for costs incurred through December 31, 2016, which has been
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NOTES TO FINANCIAL STATEMENTS
extended to December 31, 2019. The Company's share of costs recovered in 2018, 2017, and 2016, respectively are presented below (in thousands):
On October 31, 2018, APS filed a $10.2 million claim for the period July 1, 2017 through June 30, 2018. The Company's share of this claim is approximately $1.6 million. This claim is pending DOE review. The majority of the reimbursement received by the Company is expected to be credited to customers through the applicable fuel adjustment clauses.
DOE’s Construction Authorization Application for Yucca Mountain. The DOE had planned to meet its disposal obligations by designing, licensing, constructing and operating a permanent geologic repository in Yucca Mountain, Nevada. In March 2010, the DOE filed a motion to dismiss with prejudice its Yucca Mountain construction authorization application that was pending before the NRC. Several interested parties have intervened in the NRC proceeding. The Company cannot predict when spent fuel shipments to the DOE will commence.
Palo Verde has sufficient capacity at its on-site independent spent fuel storage installation (“ISFSI”) to store all of the nuclear fuel that will be irradiated during the initial operating license period, which ends in December 2027. Additionally, Palo Verde has sufficient capacity at its on-site ISFSI to store a portion of the fuel that will be irradiated during the period of extended operation, which ends in November 2047. If uncertainties regarding the U.S. government’s obligation to accept and store spent fuel are not favorably resolved, APS will evaluate alternative storage solutions that may obviate the need to expand the ISFSI to accommodate all of the fuel that will be irradiated during the period of extended operation.
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 $14.1 billion. This potential liability is covered by primary liability insurance provided by commercial insurance carriers in the amount of $450.0 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 $137.6 million, subject to an annual limit of $20.5 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 $62.1 million, with an annual payment limitation of approximately $9.7 million.
The Palo Verde Participants maintain $2.8 billion of "all risk" nuclear property insurance. The insurance provides coverage for property damage and decontamination at Palo Verde. For covered incidents involving property damage not accompanied by a release of radioactive material, the policy's coverage limit is $2.3 billion. 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 $13.5 million for the current policy period.
Palo Verde O&M Expense. Included in other O&M expenses are expenses associated with Palo Verde as follows (in thousands):
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NOTES TO FINANCIAL STATEMENTS
Four Corners
On July 6, 2016, the Company sold its interests in Four Corners for $32.0 million to 4C Acquisition, LLC, an affiliate of APS ("APS's affiliate"), and Pinnacle West Capital Corporation ("Pinnacle West"), the parent company of APS and APS's affiliate. No significant gain or loss was recorded for this sale. APS's affiliate assumed responsibility for all Four Corners capital expenditures made after July 6, 2016, which assumption is guaranteed by Pinnacle West. In addition, APS's affiliate will indemnify the Company against certain liabilities and costs related to the future operation of Four Corners, which indemnification is guaranteed by Pinnacle West. See Part II, Item 8, Financial Statements and Supplementary Data, Note D for further discussion of regulatory filings associated with Four Corners.
G. Accounting for Asset Retirement Obligation
The Company records its ARO in accordance with the FASB guidance. This guidance affects the accounting for the decommissioning of Palo Verde and the method used to report the decommissioning obligation. The Company also complies with the FASB guidance for conditional ARO, 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 ARO 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 ARO. The Company records the increase in the ARO due to the passage of time as an operating expense (accretion expense). If the Company incurs or assumes any liability in retiring any asset at the end of its useful life without a legal obligation to do so, it will record such retirement costs as incurred.
The ARO liability for Palo Verde is based upon the estimated cost of decommissioning the plant from the 2016 Study. See Part II, Item 8, Financial Statements and Supplementary Data, Note F of Notes to Financial Statements. 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, such costs have not been included in the ARO calculation. The Company maintains 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, 2018 is $276.9 million.
The 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. The 2013 Study resulted in a downward revision of $1.9 million. In the second quarter of 2017, the Company implemented the results of the 2016 Study and revised its ARO related to Palo Verde to increase its estimated cash flows from the 2013 Study to the 2016 Study. See Part II, Item 8, Financial Statements and Supplementary Data, Note F of Notes to Financial Statements. The assumptions used to calculate the increases to the Palo Verde ARO liability are as follows:
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NOTES TO FINANCIAL STATEMENTS
An analysis of the activity of the Company’s total ARO liability from January 1, 2016 through December 31, 2018, including the effects of each year’s estimate revisions, is presented below (in thousands). In 2017, the estimate revision reflects increases in the estimated cash flows related to Palo Verde's decommissioning due to implementing the 2016 Study. In 2016, the settled liabilities reflect the sale of the Company's interest in Four Corners including the related ARO.
The Company has transmission and distribution lines which are operated under various land rights agreements. Upon the expiration of any non-perpetual land rights agreement, 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 agreements are perpetual or include renewal options that the Company routinely exercises. The amount of cost of removal collected in rates for non-legal liabilities has not been material.
H. 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 29, 2014, the Company’s shareholders approved an amended and restated stock-based long-term incentive plan ("Amended and Restated 2007 LTIP") and authorized the issuance of up to 1.7 million shares of the Company's common stock for the benefit of directors and employees. Under the Amended and Restated 2007 LTIP, shares of the Company's common stock may be issued through the award or grant of non-statutory stock options, incentive stock options, stock appreciation rights, restricted stock, bonus stock, performance stock, cash-based awards and other stock-based awards. The Company may issue new shares, purchase shares on the open market, or issue shares from shares of the Company's common stock the Company has repurchased to meet the share requirements of the Amended and Restated 2007 LTIP. Beginning in 2015, shares of the Company's common stock issued for employee benefit and stock incentive plans have been issued from the shares repurchased and held in treasury stock. As discussed in Part II, Item 8, Financial Statements and Supplementary Data, Note A of Notes to Financial Statements, the Company accounts for its stock-based long-term incentive plan under the FASB guidance for stock-based compensation.
Restricted Stock with Service Condition and Other Stock-Based Awards. The Company has awarded restricted stock and other stock-based awards under its long-term incentive plan. Restrictions from resale on restricted stock awards generally lapse and awards vest over periods of one to three years, subject to continuous service requirements. 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. Other stock-based awards, granted to directors in lieu of cash for retainers and meeting fees, are fully vested and are expensed at fair value on the date of grant and are not included in the tables below.
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NOTES TO FINANCIAL STATEMENTS
The expense, deferred tax benefit, and current tax benefit recognized related to restricted stock and other stock-based awards in 2018, 2017 and 2016 is presented below (in thousands):
_____________________
(a) Any capitalized costs related to these expenses is less than $0.3 million for all years.
The aggregate intrinsic value and fair value at grant date of restricted stock and other stock-based awards which vested in 2018, 2017 and 2016 is presented below (in thousands):
The unvested restricted stock transactions for 2018 are presented below:
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(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) Excludes the stock-based retention grant to the President and Chief Executive Officer ("CEO") of 27,624 shares. See "Restricted Stock with a Market Condition (Performance Shares)" section below for further details.
The weighted average fair value per share at grant date for restricted stock and other stock-based awards granted during 2018, 2017 and 2016 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.
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NOTES TO FINANCIAL STATEMENTS
Restricted Stock with a Market Condition (Performance Shares). The Company has granted performance share awards to certain officers under the Company’s Amended and Restated 2007 LTIP, 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 2019, 2020 and 2021, subject to meeting certain performance criteria and continuous service requirements, additional performance shares could vest. In accordance with the 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. As of December 31, 2018, the maximum number of shares that can be issued under the plan are 223,885 shares.
The fair value at the date of each separate grant of performance shares was based upon a Monte Carlo simulation. The Monte Carlo simulation reflected the structure of the performance plan which calculates the share payout on performance of the Company relative to a defined peer group over a three-year performance period based upon total return to shareholders. The fair value was determined as the average payout of one million simulation paths discounted to the grant date using a risk-free interest rate based upon the constant maturity treasury rate yield curve at the grant date. The expected volatility of total return to shareholders is calculated in accordance with the performance shares' 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:
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(a) On December 15, 2015, the Company issued a stock based retention grant to the President and CEO of 27,624 shares in accordance with the Amended and Restated 2007 LTIP that is eligible for vesting based on the achievement of certain performance conditions and a five year service period, as stated in the President and CEO's employment agreement. The performance condition was met as of November 2016 as determined by the Compensation Committee and has been included in the beginning and ending balance in the table above.
(b) The unrecognized compensation expense is expected to be recognized over the weighted average remaining contractual term of the awards of approximately one year, except for the President and CEO retention grant, which is approximately two years.
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NOTES TO FINANCIAL STATEMENTS
A summary of information related to performance shares for 2018, 2017 and 2016 is presented below:
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(a) Based on a 100%, 32% and 0% performance level, respectively.
(b) Includes adjustments for estimated forfeitures.
(c) Includes President and CEO retention grant.
Repurchase Program
No shares of the Company's common stock were repurchased during the twelve months ended December 31, 2018. Detail regarding the Company's stock repurchase program are presented below:
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(a)
Represents repurchased shares and cost since inception of the stock repurchase program in 1999.
(b)
Shares repurchased does not include 86,735 treasury shares related to employee compensation arrangements that were not part of the Company's repurchase program.
(c)
Beginning in 2015, shares of the Company's common stock issued for employee benefit and stock incentive plans have been issued from the shares repurchased and held in treasury stock. The Company has issued 345,352 treasury shares since 2015 including 96,783 shares during 2018.
The Company may in the future make purchases of shares 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 the repurchased shares may be retired.
Dividend Policy
On December 28, 2018, the Company paid $14.6 million in quarterly cash dividends to shareholders. The Company paid a total of $57.5 million, $53.3 million and $49.6 million in cash dividends during the twelve months ended December 31, 2018, 2017 and 2016, respectively. On January 31, 2019, the Board of Directors declared a quarterly cash dividend of $0.36 per share payable on March 29, 2019 to shareholders of record as of the close of business on March 15, 2019.
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
Basic and Diluted Earnings Per Share
The 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 and performance shares at 100% performance level excluded from the calculation of the diluted number of common shares outstanding because their effect was antidilutive is presented below:
_____________________
(a)
Certain 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.
Authorization to Issue and Retire Shares
On January 30, 2019, the Company submitted an application with both the NMPRC and the FERC seeking approval to issue shares of common stock, including the reissuance of treasury shares, in an amount up to $200.0 million in one or more transactions. In order to align the number of shares of common stock held as treasury stock by the Company with various regulatory applications, filings and orders, on January 31, 2019, the Board of Directors of the Company approved the cancellation of 1.4 million shares of Common Stock held as treasury shares by the Company effective upon the later of approval by the FERC of the accounting treatment of the cancellation and March 31, 2019.
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
I. Accumulated Other Comprehensive Income (Loss)
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
Amounts reclassified from Accumulated Other Comprehensive Income (Loss) for the twelve months ended December 31, 2018, 2017 and 2016 are as follows (in thousands):
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
J. Long-Term Debt and Financing Obligations
Outstanding long-term debt and financing obligations, net of issuance costs, are as follows:
_____________________
(1)
Pollution Control Bonds
The Company has three series of tax exempt unsecured PCBs in aggregate principal amount of $159.8 million. The 7.25% 2009 Series A and the 7.25% 2009 Series B PCBs with an aggregate principal amount, together, of $100.6 million have optional redemptions beginning in February 2019 and April 2019, respectively, at which time the Company expects to repay, remarket or replace these bonds. The principal and related unamortized issuance cost on these PCBs were reclassified to current maturities of long-term debt as of December 31, 2018. On February 1, 2019, the Company purchased in lieu of redemption all of the 7.25% 2009 Series A with a principal amount of $63.5 million utilizing funds borrowed under the RCF. The Company is currently holding the bonds and may remarket them or replace them with debt instruments of equivalent value at a future date depending on financing needs and market conditions.
(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
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
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 Part II, Item 8, Financial Statements and Supplementary Data, Note P of Notes to Financial Statements. 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 outstanding 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. The proceeds, net of a $0.3 million discount, were used to repay outstanding short-term borrowings, fund construction expenditures and for working capital and general corporate purposes.
In December 2014, the Company issued 5.00% Senior Notes with an aggregate principal amount of $150.0 million. The proceeds, net of a $0.5 million discount, were used to fund construction expenditures and for working capital and general corporate purposes. In March 2016, the Company issued additional 5.00% Senior Notes with an aggregate principal amount of $150.0 million. The proceeds from this issuance, after deducting the underwriters' commission, were $158.1 million. These proceeds included accrued interest of $2.4 million and a $7.1 million premium before expenses. The net proceeds from the sale of these senior notes were used to repay outstanding short-term borrowings under the RCF. After the March 2016 issuance, the Company's 5.00% Senior Notes due 2044 had a total principal amount outstanding of $300.0 million.
On June 28, 2018, the Company entered into a note purchase agreement with several institutional purchasers under which the Company issued and sold $125 million aggregate principal amount of 4.22% Senior Notes due August 15, 2028. The net proceeds from the issuance of these senior notes were used to repay outstanding short-term borrowings under the RCF for working capital and general corporate purposes. The Company will pay interest on the notes semi-annually on February 15 and August 15 of each year until maturity, beginning on February 15, 2019. The Company 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 note purchase agreement requires compliance with certain covenants, including a total debt to capitalization ratio. The Company was in compliance with these requirements throughout 2018. The issuance and sale of these senior notes was made in reliance on a private placement exemption from the registration provisions of the Securities Act of 1933, as amended ("Securities Act").
(3)
RGRT Senior Notes
In 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 with various institutional purchasers. Under the terms of the agreement, RGRT issued and sold to the purchasers $110 million aggregate principal amount of Senior Notes ("RGRT Notes"). In August 2015 and 2017, $15.0 million and $50.0 million of the RGRT Notes, respectively, matured and were paid with borrowings from the RCF. The Company guarantees the payment of principal and interest on the RGRT Notes. In the Company’s financial statements, the assets and liabilities of RGRT are reported as assets and liabilities of the Company. In August 2020, the remaining $45.0 million of these RGRT Notes mature.
The sale of the RGRT Notes was made by RGRT in reliance on a private placement exemption from registration under the Securities Act. The proceeds of $109.4 million, net of issuance costs, from the sale of the RGRT Notes was used by RGRT to repay amounts borrowed under the RCF and enabled future nuclear fuel financing requirements of RGRT to be met with a combination of the RGRT Notes and amounts borrowed from the RCF.
On June 28, 2018, the RGRT and the Company entered into a note purchase agreement with several institutional purchasers under which the RGRT issued and sold $65 million aggregate principal amount of 4.07% Senior Guaranteed Notes due August 15, 2025 ("RGRT Senior Notes"). The net proceeds from the RGRT Senior Notes were used to repay outstanding short-term borrowings under the RCF to finance nuclear fuel purchases. The Company guaranteed the payment of principal and interest on the RGRT Senior Notes. RGRT’s assets, liabilities and operations are consolidated in the Company’s financial statements and the RGRT Senior Notes are included as long-term debt on the balance sheet. The issuance and sale of the RGRT Senior Notes was made in reliance on a private placement exemption from the registration provisions of the Securities Act.
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
RGRT pays interest on the senior notes above on February 15 and August 15 of each year until maturity, beginning on February 15, 2019. RGRT may redeem the senior 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 note purchase agreement requires compliance with certain covenants, including a total debt to capitalization ratio. The Company and RGRT were in compliance with these requirements throughout 2018.
(4)
Revolving Credit Facility
On January 14, 2014, the Company and RGRT entered into a second amended and restated credit agreement related to 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. As of December 31, 2016, the Company had available $300 million and the ability to increase the RCF by up to $100 million with a term ending January 2019. On January 9, 2017, the Company exercised its option to extend the maturity of the RCF by one year to January 14, 2020 and to increase the size of the facility by $50 million to $350 million.
On September 13, 2018, the Company and The Bank of New York Mellon Trust Company, N.A., as trustee of the RGRT, entered into a third amended and restated credit agreement ("RCF Agreement") with MUFG Union Bank, N.A., as administrative agent and as syndication agent, various issuing banks and lending banks party thereto. Under the terms of the RCF Agreement, the Company has available a $350 million RCF with a $50 million subfacility for the issuance of letters of credit, and the Company extended the term of the Company's existing $350 million revolving credit agreement from January 14, 2020 to September 13, 2023 ("Maturity Date"). The Company may increase the RCF by up to $50 million (to a total of $400 million) during the term of the RCF Agreement, upon the satisfaction of certain conditions more fully set forth in the RCF Agreement, including obtaining commitments from lenders or third party financial institutions. In addition, the Company may extend the Maturity Date up to two times, in each case for an additional one-year period, upon the satisfaction of certain conditions more fully set forth in the RCF Agreement, including requisite lender approval.
The RCF Agreement provides that amounts borrowed by the Company may be used for, among other things, working capital
and general corporate purposes. Any amounts borrowed by the RGRT may be used, among other things, to finance the acquisition and cost to process nuclear fuel. Amounts borrowed by the RGRT are guaranteed by the Company and the balance borrowed under the RCF Agreement is recorded as short-term borrowings on the balance sheet. The RCF Agreement is unsecured. The RCF Agreement requires compliance with certain covenants, including a total debt to capitalization ratio. The Company is in compliance with these requirements throughout 2018. In August 2017, $50.0 million aggregate principal amount of Series B 4.47% Senior Notes of the RGRT matured and was paid with borrowings from the RCF. On February 1, 2019, the Company purchased in lieu of redemption all of the 7.25% 2009 Series A PCBs with a principal amount of $63.5 million utilizing funds borrowed under the RCF. The Company is currently holding the bonds and may remarket them or replace them with debt instruments of equivalent value at a future date depending on the Company's financing needs and market conditions. As of December 31, 2018, the total amount borrowed by the RGRT was $26.2 million for nuclear fuel under the RCF. As of December 31, 2018, $23.0 million of borrowings were outstanding under this facility for working capital and general corporate purposes. The weighted average interest rate on the RCF was 3.8% as of December 31, 2018.
As of December 31, 2018, the principal amount of scheduled maturities for the next five years of long-term debt are as follows (in thousands):
_____________________
(1)
The 7.25% 2009 Series A and the 7.25% 2009 Series B PCBs with an aggregate principal amount, together, of $100.6 million have optional redemptions beginning in February 2019 and April 2019, respectively, at which time the Company expects to repay, remarket or replace these bonds.
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
K. Income Taxes
On December 22, 2017, the TCJA was enacted. The TCJA includes significant changes to the IRC, including amendments that significantly changed the taxation of business entities and includes specific provisions related to regulated public utilities. The more significant changes that impact the Company included in the TCJA are reductions in the corporate federal income tax rate from 35% to 21%, elimination of the corporate alternative minimum tax provision, additional limitations on deductions of executive compensation, and limitations on the utilization of NOLs arising after December 31, 2017, to 80% of taxable income with no carryback but with an indefinite carryforward. The specific provisions related to regulated public utilities in the TCJA generally provide for the continued deductibility of interest expense, the elimination of bonus depreciation for property acquired and placed into service after December 31, 2017, and the continuance of rate normalization requirements for accelerated depreciation benefits and changes to deferred tax balances as a result of the change in the corporate federal income tax rate. Although the Company recorded provisional estimates of the impact of the TCJA, as of the date of enactment, no significant subsequent adjustments to the provisional estimates were recorded during the one-year measurement period as permitted by the SEC in SAB 118. The results for the twelve months ended December 31, 2018 and 2017 contain the impact of the TCJA.
Reductions in accumulated deferred federal income taxes ("ADFIT") due to the reduction in the corporate income tax rate to 21% under the provisions of the TCJA will result in amounts previously collected from utility customers for these deferred taxes to be refundable to such customers, generally through reductions in future rates. The TCJA includes provisions that stipulate how these excess deferred taxes are to be returned to customers for certain accelerated tax depreciation benefits. Potential refunds of other excess deferred taxes will be determined by the Company’s regulators. The December 31, 2017 balance sheet reflects the impact of the TCJA which reduced ADFIT by $298.9 million, reduced regulatory assets by $23.6 million and increased regulatory liabilities by $275.3 million. The changes in deferred taxes were recorded at the amount of the reduced future cash flow expected to be included in rates, as required in ASC 740. These adjustments had no impact on the Company’s cash flows for the year ended December 31, 2017.
In February 2018, the FASB issued ASU 2018-02, which addresses concerns that the tax reduction due to the change in the corporate tax rate from 35% to 21% would be "stranded" in AOCI. ASU 2018-02 allows companies to reclassify stranded taxes from AOCI to retained earnings. The Company is currently evaluating the impact of ASU 2018-02 and its impact on regulated utilities. See Part II, Item 8, Financial Statements and Supplementary Data, Note B of Notes to Financial Statements for further discussion on new accounting standards.
The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and liabilities at December 31, 2018 and 2017 are presented below (in thousands):
Based on the average annual earnings before taxes for the prior three years, and excluding the effects of unusual or infrequent items, the Company believes that the deferred tax assets will be fully realized.
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
The Company recognized income tax expense for 2018, 2017 and 2016 as follows (in thousands):
As of December 31, 2018, the Company had $8.9 million of alternative minimum tax ("AMT") credit carryforwards. Based on the TCJA provisions, the Company may claim a refund of 50% of the remaining AMT credits in 2019 and 2020. Any AMT credits remaining after 2020 will be refunded in 2021. As of December 31, 2018, the Company had $11.9 million of federal and $0.8 million of state tax loss carryforwards. Under the TCJA, NOLs arising in tax years ending after 2017 cannot be carried back but can be carried forward indefinitely. The use of NOLs generated after 2017 to offset taxable income is limited to 80% of taxable income. Federal NOLs generated prior to 2018 are able to offset 100% of future taxable income to the extent available but have lives of only 20 years.
Income tax provisions differ from amounts computed by applying the statutory federal income tax rate of 21% in 2018 and 35% in 2017 and 2016 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, Arizona and New Mexico jurisdictions for years prior to 2014. In August 2017, the Company reached an agreement with the Texas Comptroller of Public Accounts and settled audits in Texas for tax years 2007 through 2011.
In the third quarter of 2016, the Company changed its accounting for state income taxes from the flow-through method to the normalization method in accordance with the 2016 PUCT Final Order and the NMPRC Final Order. Under the flow-through method, the Company previously recorded deferred state income taxes and regulatory liabilities and assets offsetting such deferred state income taxes at the expected cash flow to be reflected in future rates. Upon implementation of normalization, the Company began amortizing the net regulatory asset for deferred state income taxes to deferred income tax expense over a 15-year period as allowed by the regulators. In the third quarter of 2016, the Company began recording deferred state income tax expense as required by normalization, retroactive to January 2016 as provided in the final orders. The impact of the change was additional income tax expense of $2.3 million, $1.9 million and $5.1 million for the years ended December 31, 2018, 2017 and 2016, respectively.
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
The 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. The Company recorded a decrease of $1.2 million (net of an increase of $0.5 million), and a decrease of $0.4 million (net of an increase of $0.3 million), in 2017 and 2016, respectively, related to transmission and distribution costs and other amounts deducted in current and prior year Texas franchise tax returns. The Company recorded an unrecognized tax position of $0.5 million in 2018, $0.1 million in 2017 and a decrease of $0.3 million in 2016 related to tax credits taken and apportionment factors used in prior year Arizona income tax returns, which have been settled through audit. A reconciliation of the December 31, 2018, 2017 and 2016 amounts of unrecognized tax benefits are as follows (in thousands):
If recognized, $1.6 million of the unrecognized tax position at December 31, 2018, would reduce the effective tax rate. The Company recognized income tax expense for the increase in unrecognized tax positions of $0.5 million for the year ended December 31, 2018.
The Company recognizes in tax expense interest and penalties related to tax benefits that have not been recognized. For the years ended December 31, 2018 and 2016, the Company recognized tax expense interest of $0.6 million and $0.1 million, respectively. For the year ended December 31, 2017 the Company recognized a tax benefit of $0.2 million. The Company had approximately $1.2 million and $0.7 million accrued for the payment of interest and penalties at December 31, 2018 and 2017, respectively.
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
L. Commitments, Contingencies and Uncertainties
Power Purchase and Sale Contracts
To supplement its own generation and operating reserve requirements and to meet its RPS requirements, the Company engages in power purchase arrangements that may vary in duration and amount based on an evaluation of the Company’s resource needs, the economics of the transactions and specific RPS requirements. The Company has entered into the following significant agreements with various counterparties for the purchase and sale of electricity:
The Company has a firm 100 MW Power Purchase and Sale Agreement ("Power Purchase and Sale Agreement") with Freeport-McMoran Copper & Gold Energy Services LLC ("Freeport") that provides for Freeport to deliver energy to the Company from 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. The agreement was approved by the FERC and will continue through an initial term ending December 31, 2021, with subsequent rollovers until terminated. Upon mutual agreement, the Power Purchase and Sale Agreement allows the parties to increase the amount of energy that is purchased and sold under the agreement. The parties have agreed to increase the amount up to 125 MW through December 2021.
The Company has entered into several power purchase agreements to help meet its RPS requirements. Namely, the Company has a 25-year purchase power agreement with Hatch Solar Energy Center I, LLC to purchase all of the output from a solar photovoltaic plant located in southern New Mexico, which began commercial operation in July 2011. In June 2015, the Company entered into a consent agreement with Hatch Solar Energy Center 1, LLC to provide for additional or replacement photovoltaic modules. The Company also entered into a 20-year contract with Solar Roadrunner, LLC, a subsidiary of Global Infrastructure Partners, (formerly known as NRG Solar Roadrunner LLC) to purchase all of the output of a solar photovoltaic plant built in southern New Mexico, which began commercial operation in August 2011. In addition, the Company has 25-year purchase power agreements to purchase all of the output of two additional solar photovoltaic plants located in southern New Mexico, SunE EPE1, LLC and SunE EPE2, LLC, which began commercial operation in June 2012 and May 2012, respectively. In September 2017, Longroad Solar Portfolio Holdings, LLC purchased SunE EPE1, LLC, and in October 2017, Silicon Ranch Corporation purchased SunE EPE2, LLC with the Company's consent per the terms of both power purchase agreements.
Furthermore, the Company has a 20-year power purchase agreement with Macho Springs Solar, LLC to purchase the entire generation output delivered from the 50 MW Macho Springs solar photovoltaic plant located in Luna County, New Mexico, which began commercial operation in May 2014. Finally, the Company has a 30-year power purchase agreement with Newman Solar LLC to purchase the total output of approximately 10 MW from a solar photovoltaic plant on land subleased from the Company in proximity to Newman. This solar photovoltaic plant began commercial operation in December 2014.
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
Environmental Matters
General. The Company is subject to extensive laws, regulations and permit requirements with respect to air and greenhouse gas ("GHG") emissions, water discharges, 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.
National Ambient Air Quality Standards ("NAAQS"). Under the U.S. Clean Air Act ("CAA"), the U.S Environmental Protection Agency ("EPA") sets NAAQS for six criteria pollutants considered harmful to public health and the environment, including particulate matter, nitrogen oxide, carbon monoxide, ozone and sulfur dioxide. On October 1, 2015, the EPA released a final rule tightening the primary and secondary NAAQS for ground-level ozone from its 2008 standard levels of 75 parts per billion ("ppb") to 70 ppb. The EPA published the Final Rule on June 4, 2018, designating El Paso County, Texas, as "attainment/unclassifiable" under the 2015 ozone NAAQS and designating a section of southern Doña Ana County, New Mexico, as "nonattainment." In August 2018, several petitions for review of the Final Rule were filed in the U.S. Court of Appeals for the D.C. Circuit. One of these petitions, filed by the City of Sunland Park, New Mexico, specifically challenges the "attainment/unclassifiable" designation of El Paso County, Texas. The Company and other intervenors filed and were granted motions to intervene in the challenges to EPA's 2015 ozone NAAQS designations. A briefing schedule extending through July 2019 has been established for the case.
States, including New Mexico, that contain any areas designated as nonattainment are required to complete development of implementation plans in the 2020-2021 timeframe. Most nonattainment areas are expected to have until 2020 or 2023 to meet the primary (health) standard, with the exact attainment date varying based on the ozone level in the area. 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 NAAQS, individually or in the aggregate, could have a material impact on its operations and financial results.
Climate Change. The federal government has considered, proposed and/or finalized legislation or regulations limiting GHG emissions, including carbon dioxide. In particular, the U.S. Congress has considered legislation to restrict or regulate GHG emissions. In October 2015, the EPA published a rule establishing guidelines for states to regulate carbon dioxide emissions from existing power plants, known as the Clean Power Plan ("CPP"). Legal challenges to the CPP are ongoing. On August 31, 2018, the EPA published a proposal to replace the CPP called the Affordable Clean Energy ("ACE") rule. The ACE rule has not yet been finalized. At this time the Company cannot determine the impact that the CPP, the ACE rule, and related proposals and legal challenges may have on our financial position, results of operations or cash flows.
Environmental Litigation and Investigations. Since July 2011, the U.S. Department of Justice, on behalf of the EPA, and APS have been engaged in substantive settlement negotiations in an effort to resolve certain 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 sulfur dioxide, nitrogen oxides, and particulate matter, and that APS failed to obtain an operating permit under Title V of the CAA that reflects applicable requirements imposed by law. On June 24, 2015, the parties filed with the U.S. District Court for the District of New Mexico a settlement agreement ("CAA Settlement Agreement") resolving this matter. On August 17, 2015, the U.S. District Court entered the CAA Settlement Agreement. The agreement imposes a total civil penalty payable by the co-owners of Four Corners collectively in the amount of $1.5 million, and it requires the co-owners to pay $6.7 million for environmental mitigation projects. At December 31, 2018, the Company has accrued its remaining unpaid share of approximately $0.2 million related to this matter.
Lease Agreements
The Company leases land in El Paso, Texas, adjacent to Newman under a lease that expires in June 2033 with a renewal option of 25 years. The Company also has several other leases for office, parking facilities and equipment that expire within the next 5 years. The Company has transmission and distribution lines that are operated under various land rights agreements, including easements, leases, permits and franchises. The majority of these agreements include renewal options that the Company routinely exercises. These agreements generally do not impose any restrictions relating to issuance of additional debt, payment of dividends or entering into other lease arrangements.
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
The Company's total annual rental expense related to operating leases was $1.7 million, $2.4 million, and $1.7 million for 2018, 2017 and 2016, respectively. As of December 31, 2018, the Company’s minimum future rental payments for the next five years are as follows (in thousands):
Union Matters
The Company has approximately 1,100 employees, about 37% of whom are covered by a collective bargaining agreement. The International Brotherhood of Electrical Workers Local 960 ("Local 960") represents the Company’s employees working primarily in power generation, transmission and distribution, communications, material services, fleet services, facilities services, customer services and meter reading, and field services. The Company entered into a collective bargaining agreement effective September 3, 2016, with Local 960 for a three-year term ending September 3, 2019. The agreement provides for pay increases of 3% on September 3, 2016, September 3, 2017 and September 3, 2018, respectively. The Company presently anticipates negotiating a new three-year collective bargaining agreement to supersede the current collective bargaining agreement after the initial three-year term of the current collective bargaining agreement ends on September 3, 2019. The Company cannot predict the outcome of such negotiations and its impact on the Company's operating results and cash flows.
M. Litigation
The Company is involved in various legal, environmental, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies regarding matters arising in the ordinary course of business. In many of these matters, the Company has excess casualty liability insurance that covers the various claims, actions and complaints. The Company regularly analyzes current information and, as necessary, makes provisions in its financial statements for probable liabilities for the eventual disposition of these matters. While the outcome of these matters cannot be predicted with certainty, based upon a review of the matters and applicable insurance coverage, the Company believes that none of these matters will have a material adverse effect on the financial position, results of operations or cash flows of the Company. The Company expenses legal costs, including expenses related to loss contingencies, as they are incurred.
See Part II, Item 8, Financial Statements and Supplementary Data, Note D and Note L of Notes to Financial Statements for further discussion of the effects of government legislation and regulation on the Company as well as certain pending legal proceedings.
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
N. Employee Benefits
The Company adopted ASU 2017-07, Compensation-Retirement Benefits, effective January 1, 2018. Upon adoption of the new standard, the service cost is included in "Operations and maintenance" in the Company's Statements of Operations. The expected return on plan assets is included in "Investment and interest income, net". The amortization of prior service benefit and amortization of gains are included in "Miscellaneous non-operating income". The amortization of prior service cost and amortization of losses are included in "Miscellaneous non-operating deductions". The interest cost component of net periodic benefit cost is included in "Other interest".
The provisions in ASU 2017-07 were applied retrospectively for the income statement presentation of the service cost component and the other components of net benefit costs. The Company elected to apply the practical expedient and used the amounts previously disclosed in 2017 and 2016 as the estimation basis for applying the retrospective presentation requirements.
The Company reclassified $8.2 million to "Operations and maintenance" in the Company’s Statement of Operations for the twelve months ended December 31, 2017 by increasing (i) "Investment and interest income, net" by $21.1 million, (ii) "Miscellaneous non-operating income" by $11.3 million, (iii) "Miscellaneous non-operating deductions" by $8.4 million, and (iv) "Other interest" by $15.8 million. As a result of the reclassifications, "Operations and maintenance" increased to $10.8 million in service cost from the $2.6 million in net periodic benefit cost previously reported.
The Company reclassified $7.0 million to "Operations and maintenance" in the Company’s Statement of Operations for the twelve months ended December 31, 2016 by increasing (i) "Investment and interest income, net" by $20.7 million, (ii) "Miscellaneous non-operating income" by $9.8 million, (iii) "Miscellaneous non-operating deductions" by $7.3 million, and (iv) "Other interest" by $16.2 million. As a result of the reclassifications, "Operations and maintenance" increased to $10.8 million in service cost from the $3.8 million in net periodic benefit cost previously reported.
Retirement Plans
The Company’s Retirement Income Plan ("Retirement Plan") is a qualified noncontributory defined benefit plan. Upon retirement or death of a vested plan participant, assets of the Retirement Plan are used to pay benefit obligations under the Retirement Plan. Contributions from the Company are based on various factors, such as the minimum funding amounts required by the U.S. Internal Revenue Service, state and federal regulatory requirements, amounts requested from customers in the Company's Texas and New Mexico jurisdictions, and the annual net periodic benefit cost of the Retirement Plan, as actuarially calculated. The assets of the Retirement Plan are primarily invested in common collective trusts which hold equity securities, debt securities and cash equivalents and are managed by a professional investment manager 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 Excess Benefit Plan was adopted in 2004 and covers certain active and former employees of the Company. The net periodic 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 Retirement Plan was amended effective April 1, 2014 to offer a cash balance pension benefit as an alternative to its existing final average pay pension benefit for employees hired prior to January 1, 2014. Employees hired after January 1, 2014 are automatically enrolled in the cash balance pension benefit.
Prior to December 31, 2013, employees who completed one year of service with the Company and worked at least a minimum number of hours each year were covered by the final average pay formula of the plan. For participants that continue to be covered by the final average pay formula, retirement benefits are based on the employee’s final average pay and years of service. The cash balance pension benefit covers employees beginning on their employment commencement date or re-employment commencement date. Retirement benefits under the cash balance pension benefit are based on the employee’s cash balance account, consisting of pay credits and interest credits.
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
The obligations and funded status of the plans are presented below (in thousands):
_____________________
(a) Service cost for the Retirement Plan for 2018 excludes assumed expenses of $1,522 thousand for administrative and investment expenses paid from plan assets during the year.
Amounts recognized in the Company's balance sheets consist of the following (in thousands):
The accumulated benefit obligation in excess of plan assets is as follows (in thousands):
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
Pre-tax 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 and updated at each measurement date. The discount rate used to measure the fiscal year end obligation is based on a segmented 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, 2018 retirement plans' projected benefit obligation by 11.7%. A 1% decrease in the discount rate would increase the December 31, 2018 retirement plans' projected benefit obligation by 14.4%.
The components of net periodic benefit cost are presented below (in thousands):
_____________________
(a) Service cost for the Retirement Plan for 2018 includes assumed expenses of $1,522 thousand for administrative and investment expenses paid from plan assets during the year.
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
The changes in benefit obligations recognized in other comprehensive income are presented below (in thousands):
The total amount recognized in net periodic benefit costs and other comprehensive income are presented below (in thousands):
The following are amounts in accumulated other comprehensive income that are expected to be recognized as components of net periodic benefit cost during 2019 (in thousands):
The following are the weighted-average actuarial assumptions used to determine the net periodic benefit cost for the twelve months ended December 31:
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
The Company’s overall expected long-term rate of return on assets is 7.5% as of January 1, 2019, 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 invests the majority of its plan assets in common collective trusts which includes a diversified portfolio of domestic and international equity securities and fixed income securities. Alternative investments of the Retirement Plan are comprised of a real estate limited partnership, equity securities of real estate companies, primarily in real estate investment trusts and equity securities of listed companies involved in infrastructure activities. The expected rate of returns for the funds are assessed annually and are based on long-term relationships among major asset classes and the level of incremental returns that can be earned by the successful implementation of different active investment management strategies. Equity, real estate equity and infrastructure equity returns are based on estimates of long-term inflation rate, real rate of return, 10-year Treasury bond premium over cash, an expected equity risk premium, as well as other economic factors. Fixed income returns are based on maturity, long-term inflation, real rate of return and credit spreads. These assumptions also capture the expected correlation of returns between these asset classes over the long term.
The 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, the 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 of 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. The Common Collective Trusts are valued using the Net Asset Value ("NAV") provided by the administrator of the fund. The NAV price is quoted on a restrictive market although the underlying investments are traded on active markets. The NAV used for determining the fair value of the investments in the Common Collective Trusts have readily determinable fair values. Accordingly, such fund values are categorized as Level 1.
•
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 these investments 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.
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
The fair value of the Company’s Retirement Plan assets at December 31, 2018 and 2017, and the level within the three levels of the fair value hierarchy defined by the FASB guidance on fair value measurements are presented in the table below (in thousands):
_____________________
(a)
The Common Collective Trusts are invested in equity and fixed income securities, or a combination thereof. The investment objective of each fund is to produce returns in excess of, or commensurate with, its predefined index.
(b)
This investment is a commercial real estate partnership that purchases land, develops limited infrastructure and sells it for commercial development. The Company was restricted from selling its partnership interest during the life of the partnership, which spanned 7 years. Return on investment is realized as land is sold. The fair value of the limited partnership interest in real estate is based on the NAV of the partnership which reflects the appraised value of the land. The partnership term expired on June 30, 2016. Upon expiration, dissolution of the partnership commenced and, as a result, the general partner of the partnership is attempting to sell the remaining inventory as soon as possible at the highest pricing possible.
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
The table below reflects the changes in the fair value of investments in the real estate limited partnership during the period (in thousands):
There were no transfers in or out of Level 1 and Level 2 fair value measurements categories due to changes in observable inputs during the twelve-month periods ending December 31, 2018 and 2017. 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, 2018 and 2017.
The Company and the fiduciaries responsible for the Retirement Plan adhere 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 and the fiduciaries responsible for the Retirement Plan seek 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 manager has full discretionary authority to direct the investment of plan assets held in trust within the guidelines prescribed by the Company and the fiduciaries responsible for the Retirement Plan 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 U.S. Department of Labor ("DOL") regulations.
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. The Company provides a 50 percent matching contribution up to 6 percent of the employee’s compensation for employees who are enrolled in the final average pay pension benefit of the Retirement Plan and a 100 percent matching contribution up to 6 percent of the employee's compensation for employees who are enrolled in the cash balance pension benefit of the Retirement Plan, subject to certain other limits and exclusions. Annual matching contributions made to the savings plans for the years 2018, 2017 and 2016 were $4.6 million, $4.4 million, and $4.1 million, respectively.
Other Post-retirement Benefits
The Company provides certain other post-retirement benefits, including health care benefits for retired employees and their eligible dependents and life insurance benefits for retired employees only ("OPEB Plan"). Substantially all of the Company’s employees may become eligible for those benefits if they retire while working for the Company. Contributions from the Company are based on various factors such as the OPEB Plan's funded status, tax deductibility of contributions to the OPEB Plan, state and federal regulatory requirements, amounts requested from customers in the Company's Texas and
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
New Mexico jurisdictions and the annual net periodic benefit cost of the OPEB Plan, as actuarially calculated. The assets of the OPEB Plan are primarily invested in institutional funds which hold equity securities, debt securities and cash equivalents and are managed by a professional investment manager appointed by the Company.
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 OPEB Plan (in thousands):
_____________________
(a) Service cost for 2018 excludes assumed expenses of $204 thousand for administrative and investment expenses paid from plan assets during the year.
Amounts recognized in the Company's balance sheets consist of the following (in thousands):
Pre-tax amounts recognized in accumulated other comprehensive income consist of the following (in thousands):
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
The following are the weighted-average actuarial assumptions used to determine the accrued benefit obligations:
_____________________
(a) Pre-65 medical reaches the ultimate trend rate in 2025. Additionally, the Post-65 medical trend is assumed to be 4.50% for all years into the future.
The Company reassesses various actuarial assumptions at least on an annual basis. The discount rate is reviewed and updated at each measurement date. The discount rate used to measure the fiscal year end obligation is based on a segmented 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, 2018 accumulated post-retirement benefit obligation by 13.4%. A 1% decrease in the discount rate would increase the December 31, 2018 accumulated post-retirement benefit obligation by 17.1%.
Net periodic benefit cost is made up of the components listed below (in thousands):
_____________________
(a) Service cost for 2018 includes assumed expenses of $204 thousand for administrative and investment expenses paid from plan assets during the year.
The changes in benefit obligations recognized in other comprehensive income are presented below (in thousands):
____________________
(a) During October 2016, the Company approved and communicated a plan amendment that resulted in a remeasurement of the Company's OPEB Plan. Effective January 1, 2017, retirees and dependents that are less than 65 years of age are
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
offered a choice between a $1,000 and $2,250 deductible plan. Additionally, retirees and dependents that are 65 years of age or greater were covered by a fully insured Medicare advantage plan.
The total amount 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 2019 is a prior service benefit of $5.2 million and a net gain of $2.3 million.
The following are the weighted-average actuarial assumptions used to determine the net periodic benefit cost for the twelve months ended December 31:
_____________________
(a) The actuarial assumptions are evaluated by the Company at each measurement date. The OPEB Plan was remeasured at October 1, 2016 due to a plan amendment.
(b) Pre-65 medical reaches the ultimate trend rate in 2025. Additionally, the Post-65 medical trend is assumed to be 4.50% for all years into the future.
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, 2018 benefit obligation by $9.9 million or $7.8 million, respectively. In addition, a 1% change in said rate would increase or decrease the aggregate 2018 service and interest cost components of the net periodic benefit cost by $1.2 million or $0.9 million, respectively.
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
The Company's overall expected long-term rate of return on assets is 7.85%, as of January 1, 2019, on a pre-tax basis. The expected long-term rate of return on assets on an after-tax basis is 6.00% as of January 1, 2019. The trust's tax rate was assumed to be 35.0% at January 1, 2017 and 23.6% at January 1, 2019. 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 OPEB Plan invests the majority of its plan assets in institutional funds which includes a diversified portfolio of domestic and international equity securities and fixed income securities. Alternative investments of the OPEB Plan are comprised of a real estate limited partnership and equity securities of real estate companies, primarily in real estate investment trusts. The alternative investments also include equity securities of a dynamic, diversified portfolio designed to capture market opportunities. The underlying allocations to various asset classes in this portfolio will shift over time, but the overall strategic allocation is as follows: 75% global equity, 15% marketable real assets and 10% global fixed income. The expected rates of return for the funds are assessed annually and are based on long-term relationships among major asset classes and the level of incremental returns that can be earned by the successful implementation of different active investment management strategies. Equity returns are based on estimates of long-term inflation rate, real rate of return, 10-year Treasury bond premium over cash, an expected equity risk premium, as well as other economic factors. Fixed income returns are based on maturity, long-term inflation, real rate of return and credit spreads. These assumptions also capture the expected correlation of returns between these asset classes over the long term.
The FASB guidance on disclosure for other post-retirement benefit plans requires disclosure of fair value measurements of plan assets. To increase consistency and comparability in fair value measurements, the 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 of securities held in the mutual funds and underlying portfolios of the Other Post-retirement Benefits Plan are primarily obtained from independent pricing services. These prices are based on observable market data. The institutional funds are valued using the NAV provided by the administrator of the fund. The NAV price is quoted on a restrictive market although the underlying investments are traded on active markets. The NAV used for determining the fair value of the investments in the institutional funds have readily determinable fair values. Accordingly, such fund values are categorized as Level 1.
•
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 these investments 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.
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
The fair value of the Company’s OPEB Plan assets at December 31, 2018 and 2017 and the level within the three levels of the fair value hierarchy defined by the FASB guidance on fair value measurements are presented in the table below (in thousands):
___________________
(a)
The institutional funds are invested in equity or fixed income securities, or a combination thereof. The investment objective of each fund is to produce returns in excess of, or commensurate with, its predefined index.
(b)
This investment is a commercial real estate partnership that purchases land, develops limited infrastructure and sells it for commercial development. The OPEB Plan trust was restricted from selling its partnership interest during the life of the partnership, which spanned 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 NAV of the partnership which reflects the appraised value of the land. The partnership term expired on June 30, 2016. Upon expiration, dissolution of the partnership commenced and, as a result, the general partner of the partnership is attempting to sell the remaining inventory as soon as possible at the highest pricing possible.
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
The table below reflects the changes in the fair value of the investments in real estate during the period (in thousands):
There were no transfers in or out of Level 1 and Level 2 fair value measurements categories due to changes in observable inputs during the twelve month periods ending December 31, 2018 and 2017. 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, 2018 and 2017.
The Company and the fiduciaries responsible for the OPEB Plan adhere 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 and the fiduciaries responsible for the OPEB Plan seek 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 manager has full discretionary authority to direct the investment of plan assets held in trust within the guidelines prescribed by the Company the fiduciaries responsible for the OPEB Plan through the plan’s investment policy statement including the ability to hold cash equivalents. The investment guidelines of the investment policy statement are in accordance with the ERISA and DOL regulations.
The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid (in thousands):
Annual Short-Term Incentive Plan
The Annual Short-Term Incentive Plan ("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 specified levels of earnings and certain O&M expenses. The operational performance goals are based on reliability and customer satisfaction. If a minimum level of earnings is not attained, no amounts will be paid under the Incentive Plan, unless the Compensation Committee determines otherwise. In 2018, the Company reached the required levels of earnings, certain O&M expenses, reliability and customer satisfaction goals for an incentive payment of $11.0 million. In 2017 and 2016, the Company achieved required levels of similar goals for incentive payments of $9.7 million and $12.5 million, respectively.
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
O. Franchises and Significant Customers
Franchises
The Company operates under franchise agreements with several cities in its service territory, including one with El Paso, Texas, the largest city it serves. The franchise agreement allows the Company to utilize public rights-of-way necessary to serve its customers within El Paso. Pursuant to the El Paso franchise agreement, the Company pays to the City of El Paso, on a quarterly basis, a fee equal to 5.00% of gross revenues the Company receives for the generation, transmission and distribution of electrical energy and other services within the city. The 2005 El Paso franchise agreement set the franchise fee at 3.25% of gross revenues, but that amount has since been adjusted by two amendments. The 2010 amendment added an incremental fee equal to 0.75% of gross revenues to be placed in a restricted fund to be used by the city solely for economic development and renewable energy purposes. The 2018 amendment, approved on March 20, 2018, and applicable to bills issued on or after October 1, 2018, increased the dedicated incremental fee by 1.00% of gross revenues and extended the term of the franchise agreement by 30 years. Any assignment of the franchise agreement, including a deemed assignment as a result of a change in control of the Company, requires the consent of the City of El Paso. The El Paso franchise agreement is set to expire on July 31, 2060.
The Company does not have a written franchise agreement with Las Cruces, New Mexico, the second largest city in its service territory. The Company utilizes public rights-of-way necessary to service its customers within Las Cruces under an implied franchise pursuant to state law by satisfying all obligations under the franchise agreement that expired on April 30, 2009. The Company pays the City of Las Cruces a franchise fee of 2.00% of gross revenues the Company receives from services within the City of Las Cruces.
The Company also maintains franchise agreements with other municipalities, and applicable counties, within its service territories.
Military Installations
The Company serves HAFB, White Sands Missile Range ("White Sands") and Fort Bliss. These military installations represent approximately 2.6% of the Company's annual retail revenues. In July 2014, the Company signed an agreement with Fort Bliss under which Fort Bliss takes retail electric service from the Company under the applicable Texas tariffs. The Company serves White Sands under the applicable New Mexico tariffs. In August 2016, the Company signed a contract with HAFB under which the Company provides retail electric service and limited wheeling services to HAFB under the applicable New Mexico tariffs. As stated in the contract, HAFB will purchase the full output of a Company-owned 5 MW solar facility upon its completed construction, which occurred on October 18, 2018. HAFB's other power requirements are provided under the applicable New Mexico tariffs with limited wheeling services under the contract.
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
P. Financial Instruments and Investments
The 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 estimated 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):
__________________
(1)
On June 28, 2018, the Company issued $125 million in aggregate principal amount of 4.22% Senior Notes due August 15, 2028 and guaranteed the issuance by the RGRT of $65 million in aggregate principal amount of 4.07% Senior Guaranteed Notes due August 15, 2025. See Part II, Item 8, Financial Statements and Supplementary Data, Note J of Notes to Financial Statements.
(2)
Nuclear fuel financing, as of December 31, 2018 and December 31, 2017, is funded through $110 million and $45 million RGRT Senior Notes and $26.2 million and $88.5 million, respectively under the RCF. As of December 31, 2018, $23 million was outstanding under the RCF for working capital or general corporate purposes. As of December 31, 2017, $85.0 million was outstanding under the RCF for working capital or 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 2019, approximately $0.6 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, 2018, 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 the FASB guidance for accounting for derivative instruments and hedging activities, and, as such, were not required to be accounted for as derivatives.
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
Marketable Securities. The Company’s marketable securities, included in the NDT in the balance sheets, are reported at fair value, which was $276.9 million and $286.9 million at December 31, 2018 and 2017, respectively. The investments in the NDT are classified as available for sale debt securities, equity securities and cash and cash equivalents. These investments are recorded at their estimated fair value in accordance with FASB guidance for certain investments in debt and equity securities. On January 1, 2018, the Company adopted ASU 2016-01, Financial Instruments-Overall, which eliminates the requirements to classify investments in equity securities with readily determinable fair values as trading or available for sale and requires entities to recognize changes in fair value for these securities in net income as reported in the Statements of Operations. ASU 2016-01 requires a modified-retrospective approach and therefore, comparative information has not been restated and continues to be reported under the accounting standards in effect for those periods.
The reported fair values include gross unrealized losses on securities classified as available for sale 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 156 securities.
______________________
(2)
Includes approximately 146 securities.
The Company monitors the length of time specific securities trade below their cost basis along with the amount and percentage of the unrealized loss in determining if a decline in fair value below recorded cost of debt securities classified as available for sale is considered to be other than temporary. The Company recognizes impairment losses on certain of its available for sale debt securities deemed to be other than temporary. In accordance with the FASB guidance, these impairment losses are recognized in net income, and a lower cost basis is established for these securities. In addition, the Company will research the future prospects of individual securities as necessary. The Company does not anticipate expending monies held in trust before 2044 or a later period when decommissioning of Palo Verde begins.
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
For the twelve months ended December 31, 2018, 2017 and 2016, the Company recognized other than temporary impairment losses on its available-for-sale securities as follows (in thousands):
Investments categorized as available for sale securities also include gross unrealized gains 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):
The Company’s marketable securities include investments in mortgage backed securities, municipal, corporate and federal debt obligations. The contractual year for maturity for these available-for-sale securities as of December 31, 2018 is as follows (in thousands):
The Company's available for sale securities in the NDT are sold from time to time and the Company uses the specific identification basis to determine the amount to reclassify from AOCI into net income. The proceeds from the sale of these securities during the twelve months ended December 31, 2018, 2017, and 2016 and the related effects on pre-tax income are as follows (in thousands):
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
Upon the adoption of ASU 2016-01, Financial Instruments-Overall, on January 1, 2018, the Company records, on a modified-retrospective basis, changes in fair market value for equity securities held in the NDT in the Statements of Operations. The unrealized gains and losses recognized during the twelve months ended December 31, 2018 and related effects on pre-tax income are as follows (in thousands):
Fair Value Measurements. The 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 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 NDT investments in active exchange-traded equity securities, mutual funds and U.S. Treasury securities that are in a highly liquid and active market. The Institutional Funds are valued using the NAV provided by the administrator of the fund. The NAV price is quoted on a restrictive market although the underlying investments are traded on active markets. The NAV used for determining the fair value of the Institutional Funds-International Equity investments have readily determinable fair values. Accordingly, such fund values are categorized as Level 1.
•
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 NDT 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 analysis. Financial assets utilizing Level 3 inputs are the Company's investment in debt securities.
The securities in the NDT are valued using prices and other relevant information generated by market transactions involving identical or comparable securities. The 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.
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
The fair value of the NDT and investments in debt securities at December 31, 2018 and 2017, and the level within the three levels of the fair value hierarchy defined by the FASB guidance are presented in the table below (in thousands):
Below is a reconciliation of the beginning and ending balance of the fair value of the investment in debt securities classified as trading securities (in thousands):
_____________________
(a) These amounts are reflected in the Company's statements of operations as investment and interest income.
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
There were no transfers in or out of Level 1 and Level 2 fair value measurements categories due to changes in observable inputs during the twelve-month periods ending December 31, 2018 and 2017. There were no purchases, sales, issuances and settlements related to the assets in the Level 3 fair value measurement category during the twelve-month periods ending December 31, 2018 and 2017.
Q. Supplemental Statements of Cash Flows Disclosures
______________
(a)
The Company sold its interest in Four Corners in July 2016. The sales proceeds were reduced by the settlement of other obligations between the Company and APS and its affiliate, 4C Acquisition, LLC. See Part II, Item 8, Financial Statements and Supplementary Data, Note F of Notes to Financial Statements.
EL PASO ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS
R. 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)
Effective January 1, 2018, the Company implemented ASU 2016-01, Financial Instruments - Overall: Recognition and Measurement of Financial Assets and Liabilities. As required by the new standard, changes in the fair values of the Company's equity investments are recognized in earnings, whereas prior to 2018, such changes were recognized in accumulated other comprehensive income.
(2)
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.
(3)
The Company implemented ASU 2017-07, Compensation - Retirement Benefits, in the first quarter of 2018, and as required by the standard, reclassified certain amounts in the financial statements for 2017. See Part II, Item 8, Financial Statements and Supplementary Data, Notes B and N of Notes to Financial Statements.
(4)
For financial reporting purposes, the Company deferred any recognition of the Company's request in its 2017 Texas Retail Rate Case until it received the 2017 PUCT Final Order on December 18, 2017. Accordingly, it reported in the fourth quarter of 2017 the cumulative effect of the 2017 PUCT Final Order, which related back to July 18, 2017. See Part II, Item 8, Financial Statements and Supplementary Data, Note D of Notes to Financial Statements.
Item 9.
Item 9.
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A.
Item 9A.
Controls and Procedures
Evaluation of disclosure controls and procedures. 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 Exchange Act of our disclosure controls and procedures as defined in Rule 13a-15(e) under the Exchange Act. Based on that evaluation, our chief executive officer and our chief financial officer concluded that, as of December 31, 2018, 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 46 of this Annual Report on Form 10-K.
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 Exchange Act Rules 13a-15 or 15d-15, that occurred during the quarter ended December 31, 2018, 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
The information called for by Item 10 concerning our directors will be set forth in our definitive proxy statement for the 2019 Annual Meeting of Shareholders ("2019 Proxy Statement") under the heading "Nominees and Directors of the Company" and is incorporated herein by reference pursuant to Instruction G to Form 10-K. The information called for by Item 10 regarding our executive officers is included herein under the caption "Executive Officers of the Registrant" and is incorporated herein by reference.
The information called for by Item 10 concerning the identification of our standing audit committee will be set forth in the 2019 Proxy Statement under the caption "Committees" under the heading "Directors' Meetings, Compensation and Committees," and under the heading "Audit Committee Report" and is incorporated herein by reference pursuant to Instruction G to Form 10-K.
The information called for by Item 10 concerning our audit committee financial experts will be set forth in the 2019 Proxy Statement under the caption "Committees" under the heading "Directors' Meetings, Compensation and Committees" and is incorporated herein by reference pursuant to Instruction G to Form 10-K.
The information called for by Item 10 concerning compliance with Section 16(a) of the Exchange Act will be set forth in the 2019 Proxy Statement under the heading "Section 16(a) Beneficial Ownership Reporting Compliance," and is incorporated herein by reference pursuant to Instruction G to Form 10-K.
We have adopted a Code of Ethics. The information called for by Item 10 concerning our Code of Ethics will be set forth in the 2019 Proxy Statement under the caption "Business Conduct Policies" under the heading "Corporate Governance," and is incorporated herein by reference pursuant to Instruction G to Form 10-K.
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 28, 2019 were as follows:
Item 11.
Item 11.
Executive Compensation
The information called for by Item 11 will be set forth in the 2019 Proxy Statement under the heading "Summary of Compensation" and is incorporated herein by reference pursuant to Instruction G to Form 10-K.
Item 12.
Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
The information called for by Item 12 will be set forth in the 2019 Proxy Statement under the heading "Security Ownership of Certain Beneficial Owners and Management" and is incorporated herein by reference pursuant to Instruction G to Form 10-K.
Equity Compensation Plan Information
Item 13.
Item 13.
Certain Relationships and Related Transactions, and Director Independence
The information called for by Item 13 will be set forth in the 2019 Proxy Statement under the heading "Certain Relationships and Related Party Transactions."
Item 14.
Item 14.
Principal Accounting Fees and Services
The information called for by Item 14 will be set forth in the 2019 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 SEC, and, pursuant to Rule 12b-32 and Regulation 201.24, are incorporated herein by reference.
*
Filed herewith.
#
Management contracts or compensatory plans or arrangements required to be identified by Item 15(a)(3) of Form 10-K.
†
Agreements substantially identical in all material respects to this exhibit have been entered into between the Company and its Section 16 officers, except for the president and chief executive officer, which agreement is separately filed herewith.
Item 16.
Form 10-K Summary
None.
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 Mary E. Kipp, Nathan T. Hirschi, and Adrian J. Rodriguez, its, his or her true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution, for it, him or her and its, his or her name, place and stead, in any and all capacities, with full power of each 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 connection therewith, 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 or his or her or their substitute or substitutes, may lawfully do or cause to be done by virtue hereof.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on the 28th day of February 2019.
EL PASO ELECTRIC COMPANY
By:
/s/ MARY E. KIPP
Mary E. Kipp
President and Chief Executive Officer
(Principal Executive Officer)
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.