Excelerate Energy
Annual Report 2016

Plain-text annual report

GROWTH 2016 ANNUAL REPORT CUSTOMER T N E M T S E V N I In 2016, El Paso Electric Company (“EE” or the “Company”) achieved several significant Company milestones and celebrated a year of continued growth and development in the region we serve. Our successes in 2016 would not have been possible without the more than 1,100 dedicated employees who work hard every day to provide outstanding levels of service to our customers in west Texas and southern New Mexico. Our region is fortunate to continue benefitting from several multi-million dollar construction projects in both the public and private sectors. During this period of robust economic expansion, the Company continues to provide consistently clean, safe and reliable electrical service, all while preparing for continued customer growth and demand. We were very pleased to have obtained final orders in our rate cases in Texas and New Mexico. In Texas, which accounts for approximately 80% of our non-fuel base revenues, we received a final order that resulted in $40.9 million of non-fuel base revenues being recorded in 2016. The successful completion of our rate cases was achieved through collaboration between all parties involved, and we look forward to continuing to communicate openly with our communities and stakeholders affected by changes in our rates. In July, we completed the sale of the Company’s ownership interest in the Four Corners Generating Station, making us a coal-free utility. The sale of our interest in this plant allows EE to make use of cleaner technologies that are both more efficient and more responsive to changes in demand. This milestone, coupled with our efforts in expanding our renewable portfolio, means that we have prevented 2 billion pounds of CO2 emissions from the atmosphere, further reducing our already low carbon footprint. On July 14, 2016, we set another native system peak record of 1,892 megawatts, which surpassed our 2015 record peak of 1,794 megawatts by 5.5%. Due to the continued growth in our service territory, the Company has set a new native peak record in 15 out of the past 16 years. That same month, the Company completed the Montana Power Generating Station, a critical component in our efforts to reliably meet the region’s increasing demand, by placing Units 3 and 4 into commercial operation. Together with Units 1 and 2, these four units added a total of 354 megawatts of clean burning natural gas to our local generation fleet, and will provide enough energy to meet the needs of more than 160,000 homes in our growing service territory. In Texas, we ranked number one in reliability for both the frequency and duration of outages. This contributed to achieving above target customer satisfaction and call center performance for the year as well. All of these successes are due to our greatest asset – our employees. The continued partnership with our IBEW Local Union 960, with whom we successfully completed negotiations for a three year collective bargaining agreement in 2016, has helped us further our commitment to safely provide reliable power to our region. In 2016, our employees continued the Company’s long tradition of community service by volunteering more than 9,500 hours to our local communities. We are proud to support their dedicated participation, often in key leadership roles, in numerous organizations that benefit the communities that we serve. In looking ahead to further innovation and growth in our community, the Company is excited to make 2017 a year of great strides in energy technology and renewable energy projects. This year, we will begin our Demand Response program, which will allow customers to voluntarily subscribe to help lower peak demand during the times of highest energy usage. Additionally, we anticipate the completion of the three megawatt Texas Community Solar program, the first of its kind in Texas, and the five megawatt dedicated solar facility at the Holloman Air Force Base. These renewable energy projects will be the first large-scale solar facilities to be owned and operated by the Company, and allow us to realize one of the Company’s objectives of adding affordable large scale solar to our generation mix. We made great strides in 2016 in ensuring the continued reliability and improvement of our power grid. With the completion of the Montana Power Generating Station and upgrades to existing infrastructure, EE has added an additional $444 million of capital investment since 2015. To begin the process of recovering its most recent investments, the Company filed a general rate case in Texas on February 13, 2017. We are proud of our accomplishments over the past year, and look forward to continuing EE’s traditions of innovation, reliability and safety as we serve our region in 2017 and beyond. Mary E. Kipp Chief Executive Officer Charles A. Yamarone Chairman of the Board of Directors BOARD OF DIRECTORS Charles A. Yamarone Chairman of the Board / El Paso Electric Company Chief Corporate Governance and Compliance Officer Houlihan Lokey, a global investment bank Edward Escudero Vice Chairman of the Board / El Paso Electric Company President and Chief Executive Officer High Desert Capital, LLC, a finance company Catherine A. Allen Founder, Chairman and Chief Executive Officer The Santa Fe Group, a strategic consulting company J. Robert Brown Owner and President Brownco Capital, LLC, a private investment company OFFICERS Mary E. Kipp Chief Executive Officer John R. Boomer Senior Vice President and General Counsel Steven T. Buraczyk Senior Vice President Operations Nathan T. Hirschi Senior Vice President and Chief Financial Officer Rocky R. Miracle Senior Vice President Corporate Services and Chief Compliance Officer William A. Stiller Senior Vice President Public and Customer Affairs and Chief Human Resources Officer Robert C. Doyle Vice President Transmission and Distribution and System Planning Russell G. Gibson Vice President Controller 2016 BOARD OF DIRECTORS & OFFICERS James W. Cicconi Retired Senior Executive Vice President External and Legislative Affairs, AT&T Services, Inc. James W. Harris Managing Partner / OP Food Products, LLC, a regional agricultural enterprise Woodley L. Hunt Executive Chairman Hunt Companies, Inc., a real estate and infrastructure company Mary E. Kipp Chief Executive Officer El Paso Electric Company Thomas V. Shockley, III Retired Chief Executive Officer El Paso Electric Company Eric B. Siegel Retired Limited Partner of Apollo Advisors, LP Senior Consultant and Special Advisor to the Chairman of the Milwaukee Brewers Baseball Club Stephen N. Wertheimer Managing Director and Founding Partner W Capital Partners, a private equity firm Eduardo Gutiérrez Vice President Public, Government and Customer Affairs James A. Schichtl Vice President Regulatory Affairs David C. Hawkins Vice President System Operations, Resource Planning and Management Kerry B. Lore Vice President Customer Care Andres R. Ramirez Vice President Power Generation Guillermo Silva, Jr. Vice President Community Outreach H. Wayne Soza Vice President Compliance and Chief Risk Officer Richard E. Turner Vice President Renewables Development UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 (Mark One) _______________________ Form 10-K ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 2016 OR TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from to Commission file number 001-14206 El Paso Electric Company (Exact name of registrant as specified in its charter) Texas (State or other jurisdiction of incorporation or organization) Stanton Tower, 100 North Stanton, El Paso, Texas (Address of principal executive offices) 74-0607870 (I.R.S. Employer Identification No.) 79901 (Zip Code) Securities Registered Pursuant to Section 12(b) of the Act: Registrant’s telephone number, including area code: (915) 543-5711 Title of each class Common Stock, No Par Value Name of each exchange on which registered New York Stock Exchange Securities Registered Pursuant to Section 12(g) of the Act: None Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. YES NO Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. YES NO Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. YES NO Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). YES NO Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 126-2 of the Exchange Act. Large accelerated filer Accelerated filer Non-accelerated filer (Do not check if a smaller reporting company) Smaller reporting company Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). YES NO As of June 30, 2016, the aggregate market value of the voting stock held by non-affiliates of the registrant was $1,883,999,218 (based on the closing price as quoted on the New York Stock Exchange on that date). As of January 31, 2017, there were 40,557,679 shares of the Company’s no par value common stock outstanding. Portions of the registrant’s definitive Proxy Statement for the 2017 annual meeting of its shareholders are incorporated by reference DOCUMENTS INCORPORATED BY REFERENCE into Part III of this report.   The following abbreviations, acronyms or defined terms used in this report are defined below: DEFINITIONS Abbreviations, Acronyms or Defined Terms Terms ANPP Participation Agreement Arizona Nuclear Power Project Participation Agreement dated August 23, 1973, as amended APS ASU Company DOE El Paso FASB FERC Fort Bliss Four Corners GHG HAFB IRS kV kW kWh Las Cruces MW MWh NMPRC Net dependable generating capability NRC Palo Verde Palo Verde Participants PNM PUCT RGEC RGRT TEP White Sands Arizona Public Service Company Accounting Standards Update El Paso Electric Company United States Department of Energy City of El Paso, Texas Financial Accounting Standards Board Federal Energy Regulatory Commission Fort Bliss, the United States Army post next to El Paso, Texas Four Corners Generating Station Greenhouse gas Holloman Air Force Base Internal Revenue Service Kilovolt(s) Kilowatt(s) Kilowatt-hour(s) City of Las Cruces, New Mexico Megawatt(s) Megawatt-hour(s) New Mexico Public Regulation Commission The maximum load net of plant operating requirements that a generating plant can supply under specified conditions for a given time interval, without exceeding approved limits of temperature and stress Nuclear Regulatory Commission Palo Verde Nuclear Generating Station Those utilities that share in power and energy entitlements, and bear certain allocated costs, with respect to Palo Verde pursuant to the ANPP Participation Agreement Public Service Company of New Mexico Public Utility Commission of Texas Rio Grande Electric Cooperative Rio Grande Resources Trust Tucson Electric Power Company White Sands Missile Range (i) TABLE OF CONTENTS Item Description Page PART I 1 Business ....................................................................................................................................................................... 1 1A Risk Factors ................................................................................................................................................................. 17 1B Unresolved Staff Comments ........................................................................................................................................ 23 2 Properties ..................................................................................................................................................................... 23 3 Legal Proceedings ........................................................................................................................................................ 23 4 Mine Safety Disclosures .............................................................................................................................................. 23 PART II 5 Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities ... 24 6 Selected Financial Data ................................................................................................................................................ 26 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations ....................................... 27 7A Quantitative and Qualitative Disclosures About Market Risk ..................................................................................... 48 8 Financial Statements and Supplementary Data ............................................................................................................ 50 9 Changes in and Disagreements with Accountants on Accounting and Financial Disclosure ....................................... 109 9A Controls and Procedures .............................................................................................................................................. 109 9B Other Information ........................................................................................................................................................ 109 PART III ................................................................................................................................................................. 109 PART IV ................................................................................................................................................................. 109 (ii) FORWARD-LOOKING STATEMENTS Certain matters discussed in this Annual Report on Form 10-K, other than statements of historical fact, are "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended (the "Securities Act"), and Section 21E of the Securities Exchange Act of 1934, as amended (the "Exchange Act"). Forward-looking statements often include words like we "believe", "anticipate", "target", "project", "expect", "predict", "pro forma", "estimate", "intend", "will", "is designed to", "plan" and words of similar meaning, or are indicated by the Company's discussion of strategies or trends. Forward-looking statements describe the Company's future plans, objectives, expectations or goals. Although the Company believes that the expectations reflected in such forward-looking statements are reasonable, no assurances can be given that these expectations will prove to be correct. Such statements address future events and conditions and include, but are not limited to: • • • • • • • • • • • • capital expenditures, earnings, liquidity and capital resources, ratemaking/regulatory matters, litigation, accounting matters, possible corporate restructurings, acquisitions and dispositions, compliance with debt and other restrictive covenants, interest rates and dividends, environmental matters, nuclear operations, and the overall economy of our service area. These forward-looking statements are based on assumptions and analyses in light of the Company's experience and perception of historical trends, current conditions, expected future developments and other factors the Company believes were appropriate in the circumstances when the statements were made. Forward-looking statements by their nature involve substantial risks and uncertainties that could significantly impact expected results, and actual future results could differ materially from those described in such statements. While it is not possible to identify all factors, the Company continues to face many risks and uncertainties. Factors that would cause or contribute to such differences include, but are not limited to: • • • • • • • • • • • actions of the Company's regulators, the Company's ability to fully and timely recover its costs and earn a reasonable rate of return on its invested capital through the rates that it is permitted to charge, rates, cost recovery mechanisms and other regulatory matters including the ability to recover fuel costs on a timely basis, the ability of the Company's operating partners to maintain plant operations and manage operation and maintenance costs at the Palo Verde Nuclear Generating Station ("Palo Verde"), including costs to comply with any new or expanded regulatory or environmental requirements, reductions in output at generation plants operated by the Company, the size of the Company's construction program and its ability to complete construction on budget and on time, the Company's reliance on significant customers, the credit worthiness of the Company's customers, unscheduled outages of generating units including outages at Palo Verde, changes in customers' demand for electricity as a result of energy efficiency initiatives and emerging competing services and technologies, including distributed generation, individual customer groups, including distributed generation customers, may not pay their full cost of service, and other customers may or may not be required to pay the difference, (iii) • • • • • • • • • • • • • • • • • • • • • • changes in, and the assumptions used for, pension and other post-retirement and post-employment benefit liability calculations, as well as actual and assumed investment returns on pension plan and other post- retirement plan assets, the impact of changing cost escalation and other assumptions on the Company's nuclear decommissioning liability for Palo Verde, as well as actual and assumed investment returns on decommissioning trust fund assets, disruptions in the Company's transmission system, and in particular the lines that deliver power from its remote generating facilities, electric utility deregulation or re-regulation, regulated and competitive markets, ongoing municipal, state and federal activities, cuts in military spending or shutdowns of the federal government that reduce demand for the Company's services from military and governmental customers, political, legislative, judicial and regulatory developments, homeland security considerations, including those associated with the U.S./Mexico border region and the energy industry, changes in environmental laws and regulations and the enforcement or interpretation thereof, including those related to air, water or greenhouse gas ("GHG") emissions or other environmental matters, economic and capital market conditions, changes in accounting requirements and other accounting matters, changing weather trends and the impact of severe weather conditions, possible physical or cyber attacks, intrusions or other catastrophic events, the impact of lawsuits filed against the Company, the impact of changes in interest rates, Texas, New Mexico and electric industry utility service reliability standards, coal, uranium, natural gas, oil and wholesale electricity prices and availability, possible income tax and interest payments as a result of audit adjustments proposed by the Internal Revenue Service ("IRS") or state taxing authorities, the impact of U.S. health care reform legislation, loss of key personnel, the Company's ability to recruit and retain qualified employees and the Company's ability to successfully implement succession planning, and other circumstances affecting anticipated operations, sales and costs. These lists are not all-inclusive because it is not possible to predict all factors. A discussion of some of these factors is included in this document under the headings "Risk Factors" and "Management’s Discussion and Analysis of Financial Condition and Results of Operations –Summary of Critical Accounting Policies and Estimates" and "Management’s Discussion and Analysis of Financial Condition and Results of Operations –Liquidity and Capital Resources." This Annual Report on Form 10-K should be read in its entirety. Management cautions against putting undue reliance on forward-looking statements or projecting any future results based on such statements or present or prior earnings levels. Any forward-looking statement speaks only as of the date such statement was made, and the Company is not obligated to update any forward-looking statement to reflect events or circumstances after the date on which such statement was made, except as required by applicable laws or regulations. (iv) Item 1. Business PART I 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 capability of approximately 2,080 MW. For the year ended December 31, 2016, the Company’s energy sources consisted of approximately 49% nuclear fuel, 34% natural gas, 2% coal, 15% purchased power and less than 1% generated by Company-owned solar photovoltaic panels. The Company continues to expand its portfolio of renewable energy sources, particularly solar photovoltaic generation. As of December 31, 2016, the Company had power purchase agreements for 107 MW from solar photovoltaic generation facilities. (See "Energy Sources – Purchased Power"). The Company serves approximately 411,100 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, 2016). In addition, the Company’s wholesale sales include sales for resale to other electric utilities and power marketers. Principal industrial, public authority and other large retail customers of the Company include United States military installations, 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, 2017, the Company had approximately 1,100 employees, 38% 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 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. As of December 31, 2016, the Company’s net dependable generating capability of approximately 2,080 MW consists of the following: Facilities Station Newman Power Station Palo Verde Rio Grande Power Station Montana Power Station (Units 1, 2, 3 and 4) Copper Power Station Renewables Total Primary Fuel Type Natural Gas Nuclear Natural Gas Natural Gas Natural Gas Solar Location El Paso, Texas 100% 15.8% Wintersburg, Arizona 100% Sunland Park, New Mexico 100% 100% 100% El Paso, Texas El Paso, Texas Culberson/El Paso Counties, Texas; Dona Ana County, New Mexico Company's Share of Net Dependable Generating Capability* (MW) Company Ownership Interest 752 633 276 354 64 1 2,080 1 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 ("ANPP Participation Agreement"), the Company has limited ability to influence operations and costs at Palo Verde. • Palo Verde Operating Licenses. Operation of each of the three Palo Verde Units requires an operating license from the 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. • 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 2013, the Palo Verde Participants approved the 2013 Palo Verde decommissioning study (the "2013 Study"), which estimated that the Company must fund approximately $380.7 million (stated in 2013 dollars) to cover its share of decommissioning costs. At December 31, 2016, the Company's decommissioning trust fund had a balance of $255.7 million. Although the 2013 Study was based on the latest available information, there can be no assurance that decommissioning cost estimates attributable to the Company will not increase in the future or that regulatory requirements will not change. A 2016 Palo Verde decommissioning study is underway and is expected to be finalized in the second quarter of 2017 at which time the Company will record its effects. • Spent Fuel Storage. Pursuant to the Nuclear Waste Policy Act of 1982, as amended in 1987 (the "NWPA"), the United States 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 (the "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. On August 18, 2014, APS and the DOE entered into a settlement agreement stipulating to a dismissal of the lawsuit and payment of $57.4 million by the DOE to the Palo Verde Participants for certain specified costs incurred by Palo Verde during the period January 1, 2007 through June 30, 2011. On October 8, 2014, the Company received approximately $9.1 million, representing its share of the award, of which $7.9 million was refunded to customers through the applicable fuel adjustment clauses. On October 31, 2014, APS, acting on behalf of itself and the Palo Verde Participants, submitted to the government an additional request for reimbursement of spent nuclear fuel storage costs for the period July 1, 2011 through June 30, 2014. The accepted claim amount was $42.0 million. On June 1, 2015, the Company received approximately $6.6 million, representing its share of the award, of which $5.8 million was credited to customers through the applicable fuel adjustment clauses in March 2015. After June 2015, APS will file annual claims for the period July 1 of the then-previous year to June 30 of the then-current year. On November 2, 2015, APS filed a $12.0 million claim for the period July 1, 2014 through June 30, 2015. In February 2016, the DOE notified APS of the approval of the claim. Funds related to this claim were received in the first quarter of 2016. The Company's share of this claim is approximately $1.9 million, of which $1.6 million was credited to customers through the applicable fuel adjustment clauses in March 2016. On October 31, 2016 APS filed an $11.3 million claim for the period July 1, 2015 through June 30, 2016. The Company's share of this claim is approximately$1.8 million. On February 1, 2017, the DOE notified APS of the approval of the claim. Any reimbursement is anticipated to be received in the second quarter of 2017, and the majority of the award received by the Company will be credited to customers through 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, and the proceeding has not been conclusively decided by the NRC or the courts. Additionally, a number of interested parties have filed a variety of lawsuits in different jurisdictions around the country challenging the DOE's authority to withdraw the Yucca Mountain construction authorization 2 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 (the "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. • Waste Confidence. 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. The continued storage rule 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 United States 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. 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 kWh 3 fee (the "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 (the "Secretary") 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 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 notified Congress of his intention to suspend collection of the one-mill fee, subject to Congress’ disapproval and on May 12, 2014, APS was notified by the DOE that, effective May 16, 2014, the one-mill fee would be suspended. Electricity generated at Palo Verde and sold prior to May 16, 2014 remained subject to the one-mill fee. • NRC Oversight of the Nuclear Energy Industry in the Wake of the Earthquake and Tsunami in Japan. The NRC regulates the operation of all commercial nuclear power reactors in the United States, including Palo Verde. The NRC periodically conducts inspections of nuclear facilities and monitors performance indicators to enable the agency to arrive at objective conclusions about a licensee's safety performance. Following the March 11, 2011 earthquake and tsunami in Japan, 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 $125.0 million (the Company's share is $19.7 million) on capital enhancements related to these requirements as of December 31, 2016. • 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 $60.4 million, with an annual payment limitation of approximately $9.0 million. The Palo Verde Participants also maintain $2.75 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 $2.25 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 Newman Power Station ("Newman") 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's Rio Grande Power Station ("Rio Grande") consists of three conventional steam-electric generating units and one aeroderivative unit that operate on natural gas. The Company's Montana Power Station ("MPS") consists of four aeroderivative generating units which operate on natural gas. The units can also operate on fuel oil. The Company's Copper Power Station ("Copper") consists of a natural gas combustion turbine used primarily to meet peak demand. 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 February 17, 2015, the Company and APS entered into an asset purchase agreement (the "Purchase and Sale Agreement") providing for the sale of the Company’s interests in Four Corners to APS. Four Corners continued to provide energy to serve the Company's native load up to the closing date of the sale on July 6, 2016. Also on July 6, 2016, prior to the 4 closing of the transaction, the Company and APS entered into an amendment to the Purchase and Sale Agreement pursuant to which APS assigned its right, title and interest in the Purchase and Sale Agreement to its affiliate 4C Acquisition, LLC ("APS's affiliate"), and Pinnacle West Capital Corporation, the parent company of APS and APS's affiliate ("Pinnacle West"), guaranteed APS's affiliate's obligations under the Purchase and Sale Agreement. The sales price was $32.0 million, which was based on the net book value as defined in the Purchase and Sale Agreement. The sales price was adjusted downward by $7.0 million and $19.5 million, respectively, to reflect the assumption by APS's affiliate of the Company's obligation to pay for future plant decommissioning and mine reclamation expenses. The sales price was also adjusted downward by approximately $1.3 million for estimated closing adjustments and other assets and liabilities assumed by APS's affiliate. At the closing, the Company received approximately $4.2 million in cash, subject to post-closing adjustments. No significant gain or loss was recorded after the closing date. 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 C and Note E of Notes to Financial Statements" for further discussions. Wind and Solar Photovoltaic Facilities The Company’s Hueco Mountain Wind Ranch consisted of two wind turbines with a total capacity of 1.32 MW. The two wind turbines were decommissioned in June 2016. The Company also owns six 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 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 sources at Palo Verde and, prior to July 6, 2016, Four Corners, 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: Line Springerville-Macho Springs-Luna-Diablo Line (1) West Mesa-Arroyo Line (2) Greenlee-Hidalgo-Luna-Newman Line (3) Length (miles) 310 202 Voltage (kV) 345 345 Greenlee-Hidalgo Hidalgo-Luna Luna-Newman Eddy County-AMRAD Line (4) Palo Verde Transmission Palo Verde-Westwing (5) Palo Verde-Jojoba-Kyrene (6) 60 50 86 125 45 75 345 345 345 345 500 500 Company Ownership Interest 100.0% 100.0% 40.0% 57.2% 100.0% 66.7% 18.7% 18.7% ____________________ (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 ("PNM") West Mesa Substation located near Albuquerque, New Mexico, to the Company's Arroyo Substation located near Las Cruces, New Mexico. (3) Runs from TEP's Greenlee Substation located 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 located near Gila Bend, Arizona, then to the Kyrene Substation located near Tempe, Arizona. 5 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. 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 ("SO2"), particulate matter ("PM"), nitrogen oxides ("NOx") and mercury. Cross State Air Pollution Rule. The U.S. Environmental Protection Agency (the "EPA") promulgated the Cross-State Air Pollution Rule ("CSAPR") in August 2011, which involves requirements to limit emissions of NOx and SO2 from certain of the Company's power plants in Texas and/or purchase allowances representing other parties' emissions reductions. CSAPR was intended to replace the EPA's 2005 Clean Air Interstate Rule ("CAIR"). The U.S. Court of Appeals for the District of Columbia Circuit ("D.C. Circuit") vacated CSAPR in August 2012 and allowed CAIR to stand until the EPA issued a proper replacement. On April 29, 2014, the U.S. Supreme Court reversed and upheld CSAPR, remanding certain portions of CSAPR to the D.C. Circuit for further consideration. On July 28, 2015, the D.C. Circuit ruled that the EPA's emissions budgets for 13 states, including Texas, are invalid but left the rule in place on remand. On October 26, 2016, the EPA published its final CSAPR Update Rule with an effective date of December 27, 2016. While we are unable to determine the full impact of this rule at this time, the Company believes it is currently positioned to comply with CSAPR. National Ambient Air Quality Standards ("NAAQS"). Under the CAA, the EPA sets NAAQS for six criteria pollutants considered harmful to public health and the environment, including PM, NOx, carbon monoxide ("CO"), ozone and SO2. NAAQS must be reviewed by the EPA at five-year intervals. In 2010, the EPA tightened the NAAQS for both nitrogen dioxide ("NO2") and SO2. The EPA is considering a 1-hour secondary NAAQS for NO2 and SO2. In January 2013, the EPA tightened the NAAQS for fine PM. On October 1, 2015, following on its November 2014 proposal, 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. Ozone is the main component of smog. While not directly emitted into the air, it forms from precursors, including NOx and volatile organic compounds, in combination with sunlight. The EPA is scheduled to make attainment/nonattainment designations for the revised ozone standards by October 1, 2017. While it is currently unknown how the areas in which we operate will be designated, for nonattainment areas classified as "Moderate" and above, states, and any tribes that choose to do so, are expected to be 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. As the Company no longer owns any coal-fired generation as a result of the sale, it believes it is not responsible for a significant portion of the compliance or ongoing operational costs associated with the Mercury and Air Toxics Standards ("MATS"), the Coal Combustion Residue ("CCR") Rule, or the revised Wastewater Effluent Limitation Guidelines ("ELG"), which had been identified in previous filings that the Company has made with the SEC. Pursuant to the terms of the 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. Similar to other former owners of real property, the Company may be subject to certain future claims under environmental laws and regulations as former owner of Four Corners. The extent of such claims, if any, cannot be predicted with certainty. Climate Change. In recent years, there has been increasing public debate regarding the potential impact on global climate change. There has been a wide-ranging policy debate, both nationally and internationally, regarding the impact of GHG and possible means for their regulation. In addition, efforts have been made and continue to be made in the international community toward the adoption of international treaties or protocols that would address global climate change issues. Most recently, in April 2016 6 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. The U.S. federal government has either 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 the past few years, the EPA began using the CAA to regulate carbon dioxide and other GHG emissions, such as the 2009 GHG Reporting Rule and the EPA’s sulfur hexafluoride ("SF6") reporting rule, both of which apply to the Company, as well as the EPA’s 2010 actions to impose permitting requirements on new and modified sources of GHG emissions. In October 2015, the EPA published a final rule establishing new source performance standards ("NSPS") limiting CO2 emissions from new, modified and reconstructed electric generating units. In October 2015, the EPA also published a rule establishing guidelines for states to regulate CO2 emissions from existing power plants, as well as a proposed "federal plan" to address CO2 emissions from affected units in those states that do not submit an approvable compliance plan. The standards for existing plants are known as the Clean Power Plan ("CPP"), under which rule interim emissions performance rates must be achieved beginning in 2022 and final emissions performance rates by 2030. Legal challenges to the CPP have been filed by groups of states and industry members. On February 9, 2016, the U.S. Supreme Court issued a decision to stay the rule until legal issues are resolved. On September 27, 2016, the case against the CPP was heard in the United States Court of Appeals for the District of Columbia Circuit. We cannot at this time determine the impact of the CPP and related rules and legal challenges may have on our financial position, results of operations or cash flows. While 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. In particular, some studies suggest that climate change could affect the Company's service area by causing higher temperatures, less winter precipitation and less spring runoff, as well as by causing more extreme weather events. Such developments could change the demand for power in the region and could also impact the price or ready availability of water supplies or affect maintenance needs and the reliability of Company equipment. The Company believes that material effects on the Company's business or results of operations may result from the physical consequences of climate change, the regulatory approach to climate change ultimately selected and implemented by governmental authorities, or both. Given the very significant remaining uncertainties regarding whether and how these issues will be regulated, as well as the timing and severity of any physical effects of climate change, the Company believes it is impossible to meaningfully quantify the costs of these potential impacts at present. Environmental Litigation and Investigations. Since July 2011, the U.S. Department of Justice (the "DOJ"), on behalf of the EPA, and APS have been engaged in substantive settlement negotiations in an effort to resolve certain of the pending matters. The allegations being addressed through settlement negotiations are that APS failed to obtain the necessary permits and install the controls necessary under the CAA to reduce SO2, NOx, and PM, and that defendants failed to obtain an operating permit under Title V of the CAA that reflects applicable requirements imposed by law. On June 24, 2015, the parties filed with the U.S. District Court for New Mexico a settlement agreement ("CAA Settlement Agreement") resolving this matter. On August 17, 2015, the U.S. District Court for New Mexico 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, 2016, 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, and the cost of capital improvements and replacements at Palo Verde. Studies indicate that the Company will need additional power generation resources to meet increasing load requirements on its system and to replace retiring plants and terminated purchased power agreements, the costs of which are included in the table below. 7 The Company’s estimated cash construction costs for 2017 through 2021 are approximately $1.1 billion. Actual costs may vary from the construction program estimates shown. Such estimates are reviewed and updated periodically to reflect changed conditions. By Year (1)(2) (estimates in millions) By Function (estimates in millions) 2017 2018 2019 2020 2021 Total $ $ 215 185 203 240 242 1,085 Production (1)(2) Transmission Distribution General $ 492 131 349 113 Total $ 1,085 __________________________ (1) Does not include acquisition costs for nuclear fuel. See "Energy Sources – Nuclear Fuel." (2) Estimated production costs consist of: a. $273 million for new generating capacity, including: i. ii. $253 million of construction costs from 2018 through 2021 for a 320 MW generating resource scheduled for completion in 2023. $20 million for two utility-scale solar energy generating facilities which would have a combined maximum capacity of up to 8 MW. b. $219 million of other generation costs, including $191 million for Palo Verde. 8 General Energy Sources 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. Years Ended December 31, Power Source Nuclear Natural gas Coal Purchased power Total 2016 2015 (percentage of total kWh energy mix) 2014 49% 34% 2% 15% 100% 47% 34% 6% 13% 100% 47% 35% 5% 13% 100% 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 Public Utility Commission of Texas ("PUCT") and the New Mexico Public Regulation Commission ("NMPRC"). See "Regulation – Texas Regulatory Matters" and "Regulation – 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 and conversion services through 2018 and 45% of its requirements in 2019-2025. The participants have also contracted for 100% of Palo Verde's enrichment services through 2020, 20% of its enrichment services for 2021-2026 and all of Palo Verde's fuel assembly fabrication services through 2024. Nuclear Fuel Financing. The Company’s financing of nuclear fuel is accomplished through Rio Grande Resources Trust ("RGRT"), a Texas grantor trust, which is consolidated in the Company’s financial statements. RGRT has $95 million aggregate principal amount borrowed in the form of senior notes, of which $50 million will mature in August 2017. The Company expects to repay the $50 million of senior notes upon maturity with borrowings under the Company’s revolving credit facility (the "RCF") or refinance them. The Company guarantees the payment of principal and interest on the senior notes. The nuclear fuel financing requirements of RGRT are met with a combination of the senior notes and short-term borrowings under the 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. In 2016, 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, and this practice is expected to continue in 2017. 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 is also supplied pursuant to a long-term intrastate natural gas contract that became effective October 1, 2009 and continues through 2017. 9 Purchased Power To supplement its own generation and operating reserve requirements, and to meet required renewable portfolio standards, 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 renewable portfolio requirements. The Company has a firm 100 MW Power Purchase and Sale Agreement (the "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 2018. The Company has entered into several power purchase agreements to help meet its renewable portfolio requirements. Specifically, the Company has a 25-year purchase power agreement with Hatch Solar Energy Center I, LLC for a 5 MW solar photovoltaic project located in southern New Mexico, which began commercial operation in July 2011. 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 NRG Solar Roadrunner, LLC ("NRG") for the purchase of all of the output of a 20 MW solar photovoltaic plant built in southern New Mexico, which began commercial operation in August 2011. In addition, the Company has 25-year purchase power agreements to purchase all of the output of two additional solar photovoltaic projects located in southern New Mexico, SunE EPE1, LLC (10 MW) and SunE EPE2, LLC (12 MW), which began commercial operation in June 2012 and May 2012, respectively. Furthermore, the Company has a 20-year purchase power 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 purchase power 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 2016 to supplement the Company's generation resources during planned and unplanned outages, for economic reasons and to supply off-system sales. 10 Operating Statistics Years Ended December 31, 2015 2014 2016 Operating revenues (in thousands): Non-fuel base revenues: Retail: Residential Commercial and industrial, small Commercial and industrial, large Sales to public authorities Total retail base revenues Wholesale: Sales for resale Total non-fuel base revenues Fuel revenues: Recovered from customers during the period Under (over) collection of fuel New Mexico fuel in base rates Total fuel revenues Off-system sales: Fuel cost Shared margins Retained margins Total off-system sales Other Number of customers (end of year) (1): Total operating revenues Residential Commercial and industrial, small Commercial and industrial, large Other Total Average annual kWh use per residential customer Energy supplied, net, kWh (in thousands): Generated Purchased and interchanged Total Energy sales, kWh (in thousands): Retail: Residential Commercial and industrial, small Commercial and industrial, large Sales to public authorities Total retail Wholesale: Sales for resale Off-system sales Total wholesale Total energy sales Losses and Company use Total Native system: Peak load, kW Net dependable generating capability for peak, kW Total system: Peak load, kW (2) Net dependable generating capability for peak, kW $ $ $ $ 278,774 194,942 39,070 96,881 609,667 2,407 612,074 148,397 14,893 33,279 196,569 38,933 5,632 1,137 45,702 32,591 886,936 363,987 41,741 49 5,285 411,062 7,748 $ $ 246,265 187,436 40,411 91,244 565,356 2,455 567,811 127,765 (13,342) 72,129 186,552 52,406 11,048 1,362 64,816 30,690 849,869 358,819 40,367 49 5,261 404,496 7,763 234,371 185,388 39,239 92,066 551,064 2,277 553,341 161,052 3,110 71,614 235,776 74,716 21,117 2,147 97,980 30,428 917,525 353,885 40,038 49 5,017 398,989 7,496 8,820,006 1,552,251 10,372,257 9,585,089 1,390,946 10,976,035 9,477,129 1,390,490 10,867,619 2,805,789 2,403,447 1,030,745 1,572,510 7,812,491 62,086 1,927,508 1,989,594 9,802,085 570,172 10,372,257 1,892,000 2,080,000 2,027,000 2,080,000 2,771,138 2,384,514 1,062,662 1,585,568 7,803,882 63,347 2,500,947 2,564,294 10,368,176 607,859 10,976,035 1,794,000 2,055,000 1,992,000 2,055,000 2,640,535 2,357,846 1,064,475 1,562,784 7,625,640 61,729 2,609,769 2,671,498 10,297,138 570,481 10,867,619 1,766,000 1,879,000 1,953,000 1,879,000 ___________________________ (1) (2) The number of retail customers presented is based on the number of service locations. Includes spot sales and net losses of 135,000 kW, 198,000 kW and 187,000 kW for 2016, 2015 and 2014, respectively. 11 General Regulation 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) 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 Docket No. 44941, a request for an annual increase in non-fuel base revenues (the "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 (the "Unopposed Settlement"). On August 25, 2016, the PUCT approved the Unopposed Settlement and issued its final order in Docket No. 44941 (the "PUCT Final Order"), as proposed. The PUCT Final Order provided for: (i) an annual non-fuel base rate increase, lower annual depreciation expense, a revised return on equity for AFUDC purposes, and the inclusion of substantially all new plant in service in rate base; (ii) an additional annual non-fuel base rate increase of $3.7 million related to Four Corners costs, which will be collected through a surcharge terminating on July 12, 2017; (iii) removing the separate rate treatment for residential customers with solar systems that the Company had proposed in its August 10, 2015 filing; (iv) allowing the Company to recover $3.1 million in rate case expenses through a separate surcharge and (v) allowing the Company to recover revenues associated with the relate back of rates to consumption on and after January 12, 2016 through March 31, 2016 through a separate surcharge. 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 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 PUCT Final Order on August 25, 2016. Accordingly, it reported in the third quarter of 2016 the cumulative effect of the PUCT Final Order which related back to January 12, 2016. The effects of the PUCT Final Order on operating results for the year ended December 31, 2016 increased operating revenues by $42.4 million, decreased depreciation expense by $10.3 million and decreased other expenses, net by approximately $2.7 million for an aggregate increase in income before income taxes of $50.0 million and an increase in net income of $27.3 million. 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 Docket No.46831, a request for an increase in non-fuel base revenues of approximately $42.5 million. The Company invoked its statutory right to have its new rates relate back for consumption on and after July 18, 2017, which is the 155th day after the filing. The difference in rates that would have been billed will be surcharged or refunded to customers after the PUCT's final order in Docket No. 46831. The PUCT has the authority to require the Company to surcharge or refund such difference over a period not to exceed 18 months. The Company cannot predict the outcome or the timing of this rate case at this time. Energy Efficiency Cost Recovery Factor. On May 1, 2015, the Company filed its annual application to establish its energy efficiency cost recovery factor for 2016. In addition to projected energy efficiency costs for 2016 and a true-up to prior year actual costs, the Company requested approval of a $1.0 million bonus for the 2014 energy efficiency program results in accordance with PUCT rules. This case was assigned PUCT Docket No. 44677. A stipulation and settlement agreement was filed September 24, 2015 and the PUCT approved the settlement on November 5, 2015. The settlement approved by the PUCT included a performance bonus of $1.0 million. The Company recorded the performance bonus in operating revenues in the fourth quarter of 2015. On April 29, 2016, the Company filed its annual application to establish its energy efficiency cost recovery factor for 2017. In addition to projected energy efficiency costs for 2017 and true-up to prior year actual costs, the Company requested approval of a $0.7 million bonus for the 2015 energy efficiency program results in accordance with PUCT rules. This case was assigned PUCT Docket No. 45885. Parties in the proceeding, including PUCT staff and the City of El Paso, filed a settlement in the case that approved the Company's proposal with a reduction to the 2015 program bonus of $0.2 million. The PUCT approved the settlement on October 28, 2016. The settlement approved by the PUCT included a performance bonus of $0.5 million which was recorded in operating revenues in the third quarter of 2016. 12 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 (the "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 to be materially under-recovered. Fuel over and under-recoveries are considered material when they exceed 4% of the previous twelve months' fuel costs. All such fuel revenue and expense activities are subject to periodic final review by the PUCT in fuel reconciliation proceedings. On April 15, 2015, the Company filed a request, which was assigned PUCT Docket No. 44633, to reduce its fixed fuel factor by approximately 24% to reflect reduced fuel expenses primarily related to a reduction in the price of natural gas used to generate power. The over-recovered balance was below the PUCT's materiality threshold. The reduction in the fixed fuel factor was effective on an interim basis May 1, 2015 and approved by the PUCT on May 20, 2015. On November 30, 2016, the Company filed a request, 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. As of December 31, 2016, the Company had under-recovered fuel costs in the amount of $11.1 million for the Texas jurisdiction. 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. A procedural schedule has been adopted with hearings in April 2017. As of December 31, 2016, Texas jurisdictional fuel and purchased power costs subject to a future Texas fuel reconciliation are approximately $114.4 million. The Company cannot predict the outcome or the timing of this matter. Montana Power Station Approvals. The Company received Certificate of Convenience and Necessity ("CCN") approval from the PUCT to construct four natural gas fired generating units at MPS in El Paso County, Texas. The Company also obtained air permits from the Texas Commission on Environmental Quality (the "TCEQ") and the EPA. MPS Units 1 and 2 and associated transmission lines and common facilities were completed and placed into service in March 2015. MPS Units 3 and 4 were completed and placed into service on May 3, 2016 and September 15, 2016, respectively. 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 3 MW solar photovoltaic system located at MPS. Participation will be on a voluntary basis, and customers will 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. The Company expects completion of the solar facility and commencement of the program in the second quarter of 2017. Four Corners. On February 17, 2015, the Company and APS entered into the 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 E of Notes to Financial Statements" for further details 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 has been 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 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, and the parties are engaged in settlement discussions. At December 31, 2016, the regulatory asset associated with the Four Corners mine reclamation costs for the Company's Texas jurisdiction was approximately $7.3 million. The Company currently continues to recover its mine reclamation costs in Texas under previous orders and decisions of the PUCT. If any future determinations made by the Company's regulators result in changes to how existing regulatory assets or previously incurred costs for Four Corners are recovered in rates, any such changes would be recognized only when it becomes probable future cash flows will change as a result of such regulatory actions. 13 Other Required Approvals. The Company has obtained other required approvals for tariffs and approvals required by the Public Utility Regulatory Act (the "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 (the "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 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. 2017 New Mexico Rate Case Filing. NMPRC Case No. 15-00109-UT requires the Company to make a rate filing in New Mexico in the second quarter of 2017 using a historical test year ended December 31, 2016. Fuel and Purchased Power Costs. On January 8, 2014, the NMPRC approved the continuation of the Fuel and Purchased Power Cost Adjustment Clause (the "FPPCAC") without modification in NMPRC Case No. 13-00380-UT. Historically, fuel and purchased power costs were recovered through base rates and a 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 final order in Case No. 15-00127-UT, fuel and purchased power costs are no longer recovered through base rates 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. The Company recovers costs related to Palo Verde Unit 3 capacity and energy in New Mexico through the FPPCAC as purchased power using a proxy market price approved in Case No. 13-00380-UT. 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 Case No. 15-00127- UT. New Mexico jurisdictional costs subject to prudence review are costs from January 1, 2015 through December 31, 2016 that total approximately $114.6 million. At December 31, 2016, the Company had a net fuel over-recovery balance of $0.2 million in New Mexico. Montana Power Station Approvals. The Company received CCNs from the NMPRC to construct four units at MPS and the associated transmission lines. The Company also obtained all necessary air permits from the TCEQ and the EPA. A final order in NMPRC Case No. 13-00297-UT approving the CCN for MPS Units 3 and 4 was issued on June 11, 2014. MPS Units 1 and 2 and associated transmission lines and common facilities were completed and placed into service in March 2015. MPS Units 3 and 4 were completed and placed into service on May 3, 2016 and September 15, 2016, respectively. Four Corners. On June 15, 2016, in NMPRC Case No. 15-00109-UT, the NMPRC issued its final order approving the Company's sale and abandonment of its ownership interest in Four Corners to APS pursuant to a February 17, 2015 Purchase and Sale Agreement between the Company and APS. See Part II, Item 8, "Financial Statements and Supplementary Data, Note E of Notes to Financial Statements" for further details on the sale of Four Corners. 5 MW HAFB Facility CCN. On October 7, 2015, in NMPRC Case No. 15-00185-UT, the NMPRC issued a final order approving a CCN for a 5 MW solar power generation facility located on HAFB in the Company's service territory in New Mexico. The Company and HAFB negotiated a special retail contract, which includes power sales agreement for the facility, to replace the existing load retention agreement which was approved by final order issued October 5, 2016 in NMPRC Case No. 16-00224-UT. Construction of the solar generation facility is expected to be completed in the second quarter of 2017. Issuance of Long-Term Debt and Guarantee of Debt. On October 7, 2015 the Company received approval in NMPRC Case No. 15-00280-UT to issue up to $310.0 million of new long-term debt and to guarantee the issuance of up to $65.0 million of new debt by RGRT to finance future purchases of nuclear fuel and to refinance existing nuclear fuel debt obligations. This approval supersedes prior approvals. Under this authorization, on March 24, 2016, the Company issued $150.0 million aggregate principal amount of 5.00% Senior Notes due December 1, 2044. The net proceeds from the issuance of these senior notes, after deducting the underwriters' commission, were $158.1 million. These proceeds include accrued interest of $2.4 million and a $7.1 million premium before expenses. These senior notes constitute an additional issuance of the Company's 5.00% Senior Notes due 2044, of which $150.0 million was previously issued on December 1, 2014, for a total principal amount outstanding of $300.0 million. Other Required Approvals. The Company has obtained other required approvals for other tariffs, securities transactions, recovery of energy efficiency costs through a base rate rider and other approvals as required by the NMPRC. 14 Federal Regulatory Matters Four Corners. On June 26, 2015, APS filed an application requesting authorization from FERC to purchase 100% of the Company’s ownership interest in Units 4 and 5 of Four Corners and the associated transmission interconnection facilities and rights. On December 22, 2015, FERC issued an order approving the proposed transaction. 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 E of Notes to Financial Statements" for further details on the sale of Four Corners. Revolving Credit Facility; Issuance of Long-Term Debt and Guarantee of Debt. On October 19, 2015, the FERC issued an order in Docket No. ES15-66-000 approving the Company’s filing to issue short-term debt under the RCF up to $400.0 million outstanding at any time, to issue up to $310.0 million in long-term debt, and to guarantee the issuance of up to $65.0 million of new long-term debt by RGRT to finance future nuclear fuel purchases. The authorization is effective from November 15, 2015 through November 15, 2017. This approval supersedes prior approvals. Under this authorization, on March 24, 2016, the Company issued $150.0 million aggregate principal amount of 5.00% Senior Notes due December 1, 2044. Additionally under this authorization, 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 $50.0 million to $350.0 million. The Company still has the option to extend the facility by one additional year to January 2021 and to increase the RCF by up to $50.0 million (up to a total of $400.0 million) upon the satisfaction of certain conditions, more fully set forth in the agreement, including obtaining commitments from lenders or third party financial institutions. Additionally, the Company agreed to reduce the letters of credit commitment to $50.0 million from a total commitment, under the RCF, of $350.0 million. Other Required Approvals. The Company has obtained required approvals for rates and tariffs, securities transactions and other approvals as required by the FERC. United States Department of Energy. The DOE regulates the Company's exports of power to the Comisión Federal de Electricidad in Mexico pursuant to a license and two presidential permits issued by the DOE. The DOE is authorized to assess operators of nuclear generating facilities a share of the costs of decommissioning the DOE's uranium enrichment facilities and for the ultimate costs of disposal of spent nuclear fuel. See "Facilities – Palo Verde" for discussion of spent fuel storage and disposal costs. Sales for Resale The Company provides firm capacity and associated energy to the Rio Grande Electric Cooperative ("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 Open Access Transmission Tariff ("OATT"). The contract includes a formula- based rate that is updated annually to recover non-fuel generation costs and a fuel adjustment clause designed to recover all eligible fuel and purchased power costs allocable to the RGEC. Power Sales Contracts The Company has entered into several short-term (three months or less) off-system sales contracts throughout 2016. 15 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, which was amended in 2010, the Company pays to the City of El Paso, on a quarterly basis, a fee equal to 4.00% 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 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. 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, 2030. The Company does not have a written franchise agreement with the City of Las Cruces, the second largest city in its service territory. The Company provides electric distribution service to the City of Las Cruces under an implied franchise 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. Military Installations The Company serves HAFB, White Sands and Fort Bliss. These military installations represent approximately 2.8% 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, with HAFB's other power requirements provided under the applicable New Mexico tariffs. 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. 16 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 retail rates are subject to regulation by incorporated municipalities in Texas, the PUCT, the NMPRC and the FERC. The PUCT Final Order established our current retail base rates in Texas, effective January 12, 2016. In addition, the 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 or New Mexico rate cases will result in base rates that will allow us to fully recover our costs including a reasonable return on invested capital. There can be no assurance that regulators will determine that all of our costs are reasonable and have been prudently incurred including costs associated with future plant retirements. It is also likely that third parties will intervene in any rate cases and challenge whether our costs are reasonable and necessary. If all of our costs are not recovered, or timely recovered, through the retail base rates ultimately approved by our regulators, our profitability and cash flow could be adversely affected which, over time, could adversely affect our ability to meet our financial obligations. On February 13, 2017, we filed a general base rate case with the PUCT, Docket No. 46831 (the “2017 Texas rate case”), respectively, to establish new rates and to request recovery of new plant placed into service since April 2015 of approximately $444 million and to recover other cost of service increases. We anticipate that third parties will intervene in the 2017 Texas rate case and we expect them to challenge the reasonableness and necessity of certain of our costs. While we cannot predict the outcome or the timing of the 2017 Texas rate case at this time, we invoked our statutory right to have new rates relate back for consumption on and after July 18, 2017, which is the 155th day after the filing. The difference in rates that would have been billed will be surcharged or refunded to customers after the PUCT's final order in the 2017 Texas rate case. The PUCT has the authority to require us to surcharge or refund such differences over a period not to exceed 18 months. If the PUCT does not increase our rates adequately, our future operations, cash flow and financial condition could be materially and adversely affected. For a full discussion of these rate cases see Part II, Item 8, "Financial Statements and Supplementary Data, Note C of Notes to Financial Statements." 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. We are exposed to the risk of failing to recover all costs associated with the construction of MPS Units 3 and 4 and other new units and transmission assets. In 2014 and 2016, we issued $150.0 million in aggregate principal amount of 5.00% Senior Notes, due December 1, 2044 for a total principal amount outstanding of $300.0 million. The net proceeds from the 5.00% Senior Notes along with borrowings under our RCF were used to fund the construction of MPS and other capital additions. The costs of financing and constructing these assets are subject to review by the PUCT and NMPRC. To the extent that the PUCT or the NMPRC determines that the costs of construction are not reasonable because of cost overruns, delays or other reasons, we may not be allowed to recover these costs from customers in base rates. In addition, if future units are not completed on time, we may be required to purchase power or operate less efficient generating units to meet customer requirements. Any replacement purchased power or fuel costs will be subject to regulatory review by the PUCT and 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. 17 Weakness in the Economy and Uncertainty in the Financial Markets Could Reduce Our Sales, Hinder Our Capital Programs and Increase Our Funding Obligations for Pensions and Decommissioning In recent years, the global credit and equity markets and the overall economy have been extremely volatile. These and future events could have a number of effects on our operations 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 the stock market performance may reduce the value of our financial assets and decommissioning trust investments. 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 nuclear decommissioning trusts. 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, continued economic volatility 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. Similarly, actions or inaction of Congress and of governmental agencies can impact our operations. For example, during 2013, sales to public authorities and small commercial and industrial customers were negatively impacted by the federal government sequestration and shutdown. 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. Declines in revenues, earnings and cash flow from these events, could impact our ability to fund construction expenditures and impact the level of dividend payments. 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 United States, 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 49% of our energy requirements for the twelve months ended December 31, 2016. Palo Verde comprises approximately 25% of our total net plant-in-service and Palo Verde expenses comprise a significant portion of operation and maintenance expenses. APS is the operating agent for Palo Verde, and we have limited ability under the ANPP Participation Agreement to influence operations and costs at Palo Verde. Palo Verde operated at a capacity factor of 93.2% and 94.3% in the twelve months ended December 31, 2016 and 2015, 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. 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. 18 In New Mexico, the FPPCAC allows us to reflect current fuel and purchased power expenses in the FPPCAC and to adjust for under-recoveries and over-recoveries with a two-month lag. In Texas, fuel costs are recovered through a fixed fuel factor. In Texas, we can seek to revise our fixed fuel factor based upon our approved formula at least four months after our last revision except in the month of December. If we materially under-recover fuel costs, we may seek a surcharge to recover those costs at any time the balance exceeds a threshold material amount and is expected to continue to be materially under-recovered. During periods of significant increases in natural gas prices, 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. 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. This could materially increase our costs and 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 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 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. 19 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 had 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. Under EPA regulations finalized in May 2010, formerly known as the "Tailoring Rule", the EPA can impose GHG best achievable control technology requirements for sources, including power plants already required to implement prevention of significant deterioration under the CAA for certain other pollutants. In addition, in October 2015, the EPA published a final rule establishing NSPS limiting CO2 emissions from new, modified and reconstructed electric generating units. In October 2015, the EPA also published a rule establishing guidelines for states to regulate CO2 emissions from existing power plants, as well as a proposed "federal plan" to address CO2 emissions from affected units in those states that do not submit an approvable compliance plan. The standards for existing plants are known as the Clean Power Plan ("CPP"), under which rule interim emissions performance rates must be achieved beginning in 2022 and final emissions performance rates by 2030. Legal challenges to the CPP have been filed by groups of states and industry members. On February 9, 2016, the U.S. Supreme Court issued a decision to stay the rule until legal issues are resolved. Further, on September 3, 2016, the U.S. signed the 21st Conference of Parties Paris Agreement, which requires countries to set and "represent a progression" in GHG emission reduction goals every five years beginning in 2020. The potential impact of this agreement and 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 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 $1,213,503 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 regulatory districts (including the cities of El Paso and Las Cruces). 20 We must periodically apply for licenses and permits from these various regulatory 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. 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. 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 and distributed generation including solar rooftop projects. Customers’ increased use of energy efficiency measures and distributed generation could result in lower demand. Reduced demand due to energy efficiency measures 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 91% of revenues are directly related to the retail sales of electric power to approximately 400,000 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. 21 New Laws, Regulations and Policies Announced by the Trump Administration Could Impact Our Operations President Donald Trump campaigned on a number of issues, including increasing border security and immigration regulations, overhauling federal taxes, repealing the Patient Protection Affordable Care Act, withdrawal from the Trans Pacific Partnership agreement, enacting duties on NAFTA imports and reducing the burdens of environmental and climate control regulations. Since President Trump’s inauguration, he has initiated executive orders towards achieving some of these goals; however it is uncertain to what extent President Trump proposes additional new executive orders and the effect such orders will have on the national, regional and local economies. 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 restricting such commerce activities could reduce our customer growth rate and materially adversely affect our results of operations, financial condition and cash flows. Both the new administration and the Republicans in the House of Representatives have made public statements in support of comprehensive tax reform, including significant changes to the United States corporate income tax laws. These proposed changes include, among other things, a reduction in the corporate income tax rate, the immediate deductibility of 100% of capital expenditures, and the elimination of the interest expense deduction. We are currently unable to predict whether these reform discussions will result in any significant changes to existing tax laws, or if any such changes would have a cumulative positive or negative impact on us. However, it is possible that changes in the United States federal income tax laws could have a material adverse effect on our results of operations, financial condition, and cash flows. 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. 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 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. 22 Item 1B. Unresolved Staff Comments None. Item 2. Properties The principal properties of the Company are described in Item 1, "Business," and such descriptions are incorporated herein by reference. Transmission lines are located either on company-owned land, private rights-of-ways, easements or on streets or highways by public consent. The Company owns an executive and administrative office building and the Eastside Operations Center ( the "EOC"), which opened in early 2015, in El Paso County, Texas. The Company leases land in El Paso, Texas, adjacent to Newman under a lease which 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 four years. 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 Item 1, "Business – Environmental Matters and Regulation," and Part II, Item 8, "Financial Statements and Supplementary Data, Note C, Note L and Note K of Notes to Financial Statements" for discussion of the effects of government legislation and regulation on the Company as well as certain pending legal proceedings. Item 4. Mine Safety Disclosures Not Applicable. 23 PART II Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities. The Company’s common stock trades on the New York Stock Exchange ("NYSE") under the symbol "EE." The intraday high, intraday low and close sales prices for the Company’s common stock, as reported in the consolidated reporting system of the NYSE, and quarterly dividends per share paid by the Company for the periods indicated below were as follows: 2015 First Quarter Second Quarter Third Quarter Fourth Quarter 2016 First Quarter Second Quarter Third Quarter Fourth Quarter Sales Price High Low Close Dividends (End of period) $ $ $ $ 41.32 39.26 38.32 40.35 46.20 47.27 48.75 48.35 $ $ 35.43 33.77 33.90 35.32 37.19 42.42 44.07 42.49 38.64 34.66 36.82 38.50 45.88 47.27 46.77 46.50 $ $ 0.280 0.295 0.295 0.295 0.295 0.310 0.310 0.310 24 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, 2011 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. EE EEI Index NYSE Composite 12/31/2011 100 100 100 12/31/2012 96 102 113 12/31/2013 109 115 139 12/31/2014 128 149 145 12/31/2015 127 143 136 12/31/2016 158 168 148 As of January 31, 2017, there were 2,313 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 $49.6 million in cash dividends during the twelve months ended December 31, 2016. On January 26, 2017, the Board of Directors declared a quarterly cash dividend of $0.31 per share payable on March 31, 2017 to shareholders of record at the close of business on March 17, 2017. 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 and repurchased shares are available for issuance under employee benefit and stock incentive plans, or may be retired. On March 21, 2011, the Board of Directors authorized a repurchase of up to 2.5 million shares of the Company’s outstanding common stock (the "2011 Plan"). No shares of common stock were repurchased during the twelve months ended December 31, 2016 under the 2011 Plan. The table below provides the amount of the fourth quarter issuer purchases of equity securities. Period October 1 to October 31, 2016 November 1 to November 30, 2016 December 1 to December 31, 2016 Total Number of Shares Purchased (a) Average Price Paid per Share (Including Commissions) — — 46.50 — $ — 5,579 Total Number of Shares Purchased as Part of a Publicly Announced Program — — — Maximum Number of Shares that May Yet Be Purchased Under the Plans or Programs 393,816 393,816 393,816 _____________________ (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. For Equity Compensation Plan Information see Part III, Item 12 – "Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters." 25 Item 6. Selected Financial Data As of and for the following periods (in thousands except for share and per share data): Operating revenue Operating income Net income Basic earnings per share: Net income Years Ended December 31, 2016 886,936 194,861 96,768 2.39 2015 849,869 146,191 81,918 2.03 2014 917,525 151,163 91,428 2.27 $ $ $ $ $ $ $ $ 2013 890,362 165,635 88,583 2.20 $ $ $ $ 2012 852,881 168,658 90,846 2.27 $ $ $ $ $ $ $ Weighted average number of shares outstanding 40,350,688 40,274,986 40,190,991 40,114,594 39,974,022 Diluted earnings per share: Net income Weighted average number of shares and dilutive $ 2.39 $ 2.03 $ 2.27 $ 2.20 $ 2.26 potential shares outstanding 40,408,033 40,308,562 40,211,717 40,126,647 40,055,581 Dividends declared per share of common stock $ Cash additions to utility property, plant and equipment $ Total assets (a) Long-term debt, net of current portion (a) 1.225 225,361 $ $ 1.165 281,458 $ $ 1.105 277,078 $ $ 1.045 237,411 $ $ 0.97 202,387 $ 3,376,278 $ 3,200,607 $ 3,033,400 $ 2,748,139 $ 2,637,183 $ 1,195,513 $ 1,122,660 $ 1,122,235 Common stock equity $ 1,074,396 $ 1,016,538 $ 984,254 $ $ 988,436 943,833 $ $ 987,960 824,999 ________________ (a) The Company implemented Accounting Standards Update ("ASU") 2015-03, Interest- Imputation of Interest (Topic 715) and ASU 2015-17, Balance Sheet Classification of Deferred Taxes in the first quarter of 2016, retrospectively to all periods presented in the table above. 26 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, 2016, we had recorded regulatory assets currently subject to recovery in future rates of approximately $118.9 million and regulatory liabilities of approximately $18.4 million as discussed in greater detail in Part II, Item 8, Financial Statements and Supplementary Data, Note D of the Notes to Financial Statements. Regulatory tax assets of approximately $66.7 million, primarily related to the regulatory treatment of the equity portion of allowance for funds used during construction ("AFUDC") and excess deferred income taxes, are included in regulatory assets. In the event we determine that we can no longer apply the Financial Accounting Standards Board's (the "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, we record fuel transactions such that fuel revenues, including fuel costs recovered through the Fuel and Purchased Power Cost Adjustment Clause (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. As of December 31, 2016, Texas jurisdictional fuel and purchased power costs subject to a future Texas fuel reconciliation are approximately $114.4 million. The NMPRC approved the continuation of its use of the FPPCAC without modification and the Company’s application requesting reconciliation of fuel and purchased power costs through December 2012 in Case No. 13-00380-UT. 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 Case No. 15-00127-UT. New Mexico jurisdictional costs subject to prudence review are costs from January 1, 2015 through December 31, 2016 that total approximately $114.6 million. The Company recovers fuel and purchased power costs from the 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 27 in February following the prior calendar year. As of December 31, 2016, the RGEC fuel costs subject to review were approximately $1.4 million. Decommissioning Costs and Estimated Asset Retirement Obligation Pursuant to the ANPP Participation Agreement, the rules and regulations of the Nuclear Regulatory Commission 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 $79.6 million and represents approximately 97% of our total ARO balance of $81.8 million as of December 31, 2016. A 10% increase in the estimates of future Palo Verde decommissioning costs at current price levels would have increased the ARO liability by approximately $7.8 million at December 31, 2016. For further details see Part II, Item 8, "Financial Statements and Supplementary Data, Note E of Notes to Financial Statements." 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 Nuclear Regulatory Commission, PUCT and the ANPP Participation Agreement. Historically, in Texas and New Mexico, we have been permitted to collect the funding requirements for our nuclear decommissioning trusts 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 nuclear decommissioning trusts. Our decommissioning trust funds consist of equity securities and fixed income instruments and are carried at fair value. We face interest rate risk on the fixed income instruments, which consist primarily of municipal, federal and corporate bonds and which were valued at $119.9 million as of December 31, 2016. A hypothetical 10% increase in interest rates would have reduced the fair values of these funds by $1.4 million at December 31, 2016. Our decommissioning trust funds also include marketable equity securities of approximately $129.8 million at December 31, 2016. A hypothetical 20% decrease in equity prices would have reduced the fair values of these funds by $26.0 million at December 31, 2016. Declines in market prices could require that additional amounts be contributed to our nuclear decommissioning trusts to maintain minimum funding requirements. We do not anticipate expending monies held in the nuclear decommissioning trusts 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, 2016 totaled $129.9 million and are recorded as liabilities on our balance sheet. The net periodic benefit costs for these plans totaled $3.8 million for the twelve months ended December 31, 2016. During October 2016, we approved and communicated a plan amendment that resulted in a remeasurement of our other post- retirement benefit plan. Effective January 1, 2017, retirees and dependents that are less than 65 years of age are offered a choice between a $1,000 and $2,250 deductible plan. Additionally, retirees and dependents that are 65 years of age or greater are covered by a fully insured Medicare advantage plan. The impact of these plan changes was a reduction in the other post-retirement benefit plan obligation of $32.7 million as of December 31, 2016. 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 2016, 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, 2016, the corresponding weighted-average discount rates range from 3.76% to 4.36% depending upon the benefit plan. 28 Our overall expected long-term rate of return on assets for the pension trust fund is 7.0% effective January 1, 2017, 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 4.875% effective January 1, 2017. 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 6.5%, 7.5%, 4.5% and 10.5% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2017 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. In 2016, we changed the method used to estimate the service and interest components of net periodic benefit cost for pension and other post-retirement benefits. This change, compared to the previous method, resulted in a decrease in the service cost and interest cost components in 2016, and is expected to result in a decrease in the service cost and interest cost components in future periods. Historically, we estimated service and interest costs utilizing a single weighted-average discount rate derived from the yield curve used to measure the benefit obligation at the beginning of the period. In 2016, we elected to utilize a full yield curve approach to estimate these components by applying the specific spot rates along the yield curve used in the determination of the benefit obligation to the relevant projected cash flows. We believe the new approach provides a more precise measurement of service and interest costs by aligning the timing of the plan’s liability cash flows to the corresponding spot rates on the yield curve. We accounted for this change as a change in accounting estimate and accordingly, accounted for this prospectively. The change in estimate decreased the service and interest components of net periodic benefit cost for pension and other post-retirement benefits in 2016 by approximately $2.9 million and $0.8 million, respectively. The following table reflects the sensitivities that a change in certain actuarial assumptions would have had on the December 31, 2016 reported pension liability and our 2016 reported pension expense (in thousands): Actuarial Assumption Discount rate: Increase 1% Decrease 1% Expected long-term rate of return on plan assets: Increase 1% Decrease 1% Compensation rate: Increase 1% Decrease 1% Increase (Decrease) Impact on Pension Liability Impact on Pension Expense $ (41,843) 51,463 $ N/A N/A 6,615 (6,002) (3,601) 4,343 (2,698) 2,698 1,241 (1,106) 29 The following chart reflects the sensitivities that a change in certain actuarial assumptions would have had on the December 31, 2016 other post-retirement benefit obligations and our 2016 reported other post-retirement benefit expense (in thousands): Actuarial Assumption Discount rate: Increase 1% Decrease 1% Healthcare cost trend rate: Increase 1% Decrease 1% Expected long-term rate of return on plan assets: Increase 1% Decrease 1% Tax Accruals Increase (Decrease) Impact on Other Post- retirement Benefit Obligation Impact on Other Post- retirement Benefit Expense Impact on Other Post- retirement Service and Interest Cost $ (9,631) 12,246 $ (1,329) 1,595 $ 11,222 (8,951) N/A N/A 2,342 (1,919) (376) 376 (276) 350 1,252 (973) N/A N/A 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. 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, 2016. 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 $2.6 million as of December 31, 2016. The following is an overview of our results of operations for the years ended December 31, 2016, 2015 and 2014. Net income and basic earnings per share for the years ended December 31, 2016, 2015 and 2014 are shown below: Overview Net income (in thousands) Basic earnings per share Years Ended December 31, 2016 2015 2014 $ $ 96,768 2.39 $ 81,918 2.03 91,428 2.27 Financial Effect of the PUCT Final Order On August 25, 2016, the PUCT approved the Unopposed Settlement and issued its final order in Docket No.44941 (the "PUCT Final Order"), as proposed. See Part II, Item 8, "Financial Statements and Supplementary Data, Note C of Notes to Financial Statements." 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 PUCT Final Order on August 25, 2016. Accordingly, in the third quarter of 2016, the Company reported the cumulative effect of the PUCT Final Order, which related back to January 12, 2016. 30 The increase (decrease) on operations resulting from the PUCT Final Order is categorized in the following periods based on consumption (in thousands): Three Months Ended Twelve Months Ended March 31, 2016 June 30, 2016 September 30, 2016 December 31, 2016 December 31, 2016 Category Retail non-fuel base rate increase: Relate back $ 4,782 $ — $ — $ — $ 4,782 Interim rates Additional non-fuel base rate increase for Four Corners Base rate increase 457 708 — 10,417 15,138 — 26,012 867 — 1,328 — 853 6,321 3,756 6,321 Retail non-fuel base rate increase, total $ 5,947 $ 11,284 $ 16,466 $ 7,174 $ 40,871 Miscellaneous service revenues Revenue taxes Depreciation Rate case expense AFUDC Pre-tax increase Income tax expense (a) After-tax increase 353 (19) 2,491 — (106) 8,666 4,104 400 (436) 2,510 — (87) $ 13,671 5,677 4,562 $ 7,994 $ $ $ $ 390 (643) 2,412 (600) (72) 17,953 7,221 10,732 $ $ 379 (238) 2,849 (395) (52) 9,717 5,714 4,003 $ $ 1,522 (1,336) 10,262 (995) (317) 50,007 22,716 27,291 (a) 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 PUCT Final Order and the NMPRC Final Order. The impact of the change was additional income tax expense of $5.1 million for the twelve months ended December 31, 2016. 31 The following table and accompanying explanations show the primary factors affecting the after-tax change in income between the calendar years ended 2016 and 2015, 2015 and 2014, and 2014 and 2013 (in thousands): Prior year December 31 net income Changes (net of tax): Increased (decreased) retail non-fuel base revenues Decreased (increased) depreciation and amortization Increased (decreased) non-base revenue, net of energy expense Changes in the effective tax rate (Decreased) increased allowance for funds used during construction Increased interest on long-term debt (net of capitalized interest) (Decreased) increased investment and interest income Increased taxes other than income taxes Other Current year December 31 net income $ 2016 2015 2014 $ 81,918 $ 91,428 $ 88,583 28,802 (a) 3,580 (d) 804 (5,343) (i) (4,887) (k) (3,700) (n) (2,784) (p) (1,168) (s) (454) 96,768 $ 9,290 (b) (4,214) (e) (5,370) (g) 1,540 (j) (4,953) (l) (4,516) (o) 3,084 (q) (641) (3,730) 81,918 $ (3,533) (c) (2,415) (f) 3,779 (h) 15 6,157 (m) (390) 5,309 (r) (3,252) (t) (2,825) 91,428 ______________________ Footnotes reflect pre-tax amounts (a) (b) Increased retail non-fuel base revenues primarily due to the recognition of $40.9 million related to the PUCT Final Order. Retail non-fuel base revenues increased, primarily due to (i) increased revenues of $11.9 million from our residential customers due to hotter weather in the third quarter of 2015 contributing to a 4.9% increase in kWh sales; (ii) increased revenues of $2.0 million from small commercial and industrial customers due to a 1.1% increase in kWh sales resulting from hotter weather and a 1.6% increase in the average number of customers and (iii) a $1.2 million increase from large commercial and industrial customers. These increases were partially offset by an $0.8 million decrease from sales to public authorities due to a military installation moving a portion of their load to an interruptible rate. Retail non-fuel base revenues decreased, primarily due to (i) a $3.0 million reduction in revenues from sales to public authorities reflecting increased use of an interruptible rate at a military installation in our service territory as well as other energy saving programs at military installations; (ii) a $2.3 million decrease in sales to residential customers primarily due to milder weather; and (iii) a $1.0 million decrease in sales to large commercial and industrial customers. 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 and the NMPRC Final Order and (ii) the sale of the Company's interest in Four Corners. These decreases were partially offset by an increase in plant, primarily due to MPS Units 1 and 2 and the 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. Depreciation and amortization increased due to increased depreciable plant balances including MPS Units 1 and 2 and the EOC which began commercial operation in the first quarter of 2015, partially offset by a change in the estimated useful life of certain large intangible software systems. Depreciation and amortization increased due to increased depreciable plant balances including Rio Grande Unit 9, which began commercial operation in the second quarter of 2013. Non-base revenues, net of energy expenses decreased due to: (i) a decrease of $5.3 million in deregulated Palo Verde Unit 3 revenues; (ii) the recognition in 2014 of Palo Verde performance rewards of $2.2 million associated with the 2009 to 2012 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. 41852; and (iii) a decrease of $0.7 million in energy efficiency bonuses awarded. These decreases were partially offset by an increase of $1.7 million in transmission wheeling revenues. Non-base revenues, net of energy expenses increased due to: (i) recognition of $2.2 million in Palo Verde performance rewards associated with the 2009 to 2012 performance periods, net of disallowed fuel and purchased power costs related to the resolution of the Texas fuel reconciliation proceeding designated as PUCT Docket No. 41852; (ii) a $2.0 million Texas Energy Efficiency bonus awarded in the fourth quarter of 2014 and (iii) an increase of $3.6 million in deregulated Palo Verde Unit 3 revenues. The increase was partially offset by a decrease of $3.3 million in transmission wheeling revenues. The effective tax rate increased due to the change to normalize state income taxes in accordance with the PUCT Final Order and the NMPRC Final Order. (c) (d) (e) (f) (g) (h) (i) 32 (j) (k) (l) (m) (n) (o) (p) (q) (r) (s) (t) The effective tax rate decreased due to a decrease in state income taxes and an increase in decommissioning income. These decreases were partially offset by a decrease in AEFUDC and the loss of the domestic production activities deduction in 2015. 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 PUCT Final Order. AFUDC decreased primarily due to lower balances of construction work in process primarily due to MPS Units 1 and 2, and the EOC being placed in service during the first quarter of 2015 and a reduction in the AFUDC rate. AFUDC increased, primarily due to higher balances of CWIP subject to AFUDC, reflecting construction work in progress on MPS and the EOC. Interest on long-term debt increased, primarily due to the $150.0 million principal amount of senior notes issued in March 2016. Interest on long-term debt increased, primarily due to the $150.0 million principal amount of senior notes issued in December 2014. Investment and interest income decreased primarily due to lower realized gains on securities sold from the Company’s Palo Verde decommissioning trust in 2016 compared to 2015. The net gains reported in 2016 and 2015 are primarily the result of the Company's efforts to re-balance and further diversify its Palo Verde decommissioning trust fund investments. Investment and interest income increased, primarily due to further diversification and re-balancing our Palo Verde decommissioning trust fund equity portfolio. Investment and interest income increased, primarily due to increased gains on the sales of equity investments in our Palo Verde decommissioning trust funds. 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. Taxes other than income taxes increased, primarily due to higher property tax values and assessment rates. Additionally, in the first quarter of 2014, the Arizona tax district in which Palo Verde operates adjusted its 2013 property tax rate, resulting in an additional charge of $1.3 million. 33 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. Historical Results of Operations Operating revenues We realize revenue from the sale of electricity to retail customers at regulated rates and the sale of energy in the wholesale power market generally at market-based prices. Sales for resale, which are FERC-regulated cost-based wholesale sales within our service territory, accounted for less than 1% of revenues in each of 2016, 2015 and 2014. Revenues from the sale of electricity include fuel costs that are recovered from our customers through fuel adjustment mechanisms. Historically, 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: Residential Commercial and industrial, small Commercial and industrial, large Sales to public authorities Total retail non-fuel base revenues Years Ended December 31, 2015 2014 2016 46% 32 6 16 100% 44% 33 7 16 100% 42% 34 7 17 100% No retail customer accounted for more than 4% of our non-fuel base revenues during such periods. As shown in the table above, residential and small commercial customers comprise 78% 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 from 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: January 1 to March 31 April 1 to June 30 July 1 to September 30 October 1 to December 31 Total Years Ended December 31, 2016 2015 2014 17% 25 38 20 100% 18% 26 35 21 100% 19% 27 33 21 100% 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 2016, 2015 and 2014. Cooling degree days Heating degree days 2016 2015 2014 2,811 1,851 2,839 2,095 2,671 1,900 10-year Average 2,732 2,157 34 Customer growth is a key driver in the growth of retail sales. The average number of retail customers grew 1.5% and 1.4% in 2016 and 2015, respectively. See the tables presented on pages 37 and 38 which provide detail on the average number of retail customers and the related revenues and kWh sales. Retail non-fuel base revenues. Retail non-fuel base revenues increased primarily due to the recognition of $40.9 million related to the PUCT Final Order. Excluding the $40.9 million PUCT Final Order impact, for the twelve months ended December 31, 2016, retail non-fuel base revenues increased $3.4 million, pre-tax, or 0.6%, compared to the twelve months ended December 31, 2015. This increase was primarily due to increased revenues from residential customers of $3.5 million due to a 1.3% increase in kWh sales and increased revenues from small commercial and industrial customers of $2.5 million due to a 0.8% increase in kWh sales. Increased kWh sales from residential customers and small commercial and industrial customers were driven by a 1.4% and 1.9% increase in the average number of customers, respectively, offset in part by milder weather during the twelve months ended December 31, 2016 compared to the twelve months ended December 31, 2015. Revenues decreased $2.4 million from large commercial and industrial customers during the twelve months ended December 31, 2016 compared to the twelve months ended December 31, 2015 due to a 3.0% decrease in kWh sales, due primarily to reduced demand by the steel manufacturing industry, and a decrease in surcharges billed to a large customer in 2016 compared to 2015. Revenues decreased $0.2 million from public authority customers reflecting a 0.8% decrease in kWh sales. Cooling degree days were relatively consistent with 2015 and were 2.9% over the 10-year average. Heating degree days decreased 11.6% in 2016, compared to 2015, and were 14.2% below the 10- year average. Retail non-fuel base revenues increased $14.3 million, or 2.6%, for the twelve months ended December 31, 2015 when compared to the twelve months ended December 31, 2014. This increase includes an $11.9 million increase in revenues from residential customers and a $2.0 million increase in revenues from small commercial and industrial customers reflecting hotter summer weather and increases of 1.3% and 1.6%, respectively, in the average number of residential customers and small commercial and industrial customers. KWh sales to public authorities increased 1.5% while revenue declined by $0.8 million, primarily due to a military installation moving a portion of their load to an interruptible rate. Retail non-fuel revenues from large commercial and industrial customers increased $1.2 million due to a surcharge billed to a large customer. Cooling degree days increased 6.3% in 2015, when compared to the same period in the prior year, and were 5.3% over the 10-year average. Heating degree days increased 10.3% for 2015, compared to 2014, and were 3.6% below the 10-year average. 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 Texas, fuel costs are recovered through a fixed fuel factor. We can seek to revise our 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. On April 15, 2015, we filed a request, which was assigned PUCT Docket No. 44633, to reduce our fixed fuel factor by approximately 24% to reflect an expected reduction in fuel expense. The over-recovered balance was below the materiality threshold. The reduction in the fixed fuel factor was effective on an interim basis May 1, 2015 and was approved by the PUCT on May 20, 2015. On November 30, 2016, we filed a request, which was assigned PUCT Docket No. 46610, to increase our 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 3, 2017 and approved by the PUCT on January 10, 2017. On September 27, 2016, we 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. In New Mexico, effective July 1, 2016, with the implementation of the NMPRC Final Order, fuel and purchased power costs will no longer be recovered through base rates, as it was historically, but will be completely recovered through the Fuel and Purchased Power Cost Adjustment Clause (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. 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. In March 2015 and March 2016, $5.8 million and $1.6 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 under-recovered fuel costs by $14.9 million in the twelve months ended December 31, 2016. We over-recovered fuel costs by $13.3 million and under-recovered $3.1 million in the twelve months ended December 31, 2015 and 2014, respectively. At December 31, 2016, we had a net fuel under-recovery balance of $10.9 million, including an under-recovery of $11.1 million in Texas offset by an over-recovery of $0.2 million in New Mexico. 35 Off-system sales. Off-system sales are wholesale sales into markets outside our service territory. Off-system sales are primarily made in off-peak periods when we have competitive generation capacity available after meeting our regulated service obligations. We 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. For the period April 1, 2014 through June 30, 2015, our total share of margins assignable to the Texas retail jurisdiction, on arbitrage and non-arbitrage off-system sales, could not exceed 10% of the total margins assignable to the Texas retail jurisdiction on all off-system sales. We are currently sharing 90% of off- system sales margins with our New Mexico customers, and 25% of our off-system sales margins with our sales for resale customer under the terms of their contract. Typically, we realize a significant portion of our off-system sales margins in the first quarter of each calendar year when our native load is lower than at other times of the year, allowing for the sale in the wholesale market of relatively larger amounts of off-system energy generated from lower cost generating resources. Palo Verde's availability is an important factor in realizing these off-system sales margins. The table below shows MWhs, sales revenue, fuel cost, total margins and retained margins made on off-system sales for the twelve months ended December 31, 2016, 2015 and 2014 (in thousands, except for MWhs). MWh sales Sales revenue Fuel cost Total margins Retained margins Years Ended December 31, 2016 1,927,508 45,702 38,933 6,769 1,137 $ $ $ $ 2015 2,500,947 64,816 52,406 12,410 1,362 $ $ $ $ 2014 2,609,769 97,980 74,716 23,264 2,147 $ $ $ $ Off-system sales revenue decreased $19.1 million, or 29.5%, and the related retained margins decreased $0.2 million, or 16.5%, for the twelve months ended December 31, 2016 when compared to 2015 as a result of lower average market prices for power and a 22.9% decrease in MWh sales. Off-system sales revenues decreased $33.2 million, or 33.8%, and the related retained margins decreased $0.8 million, or 36.6%, for the twelve months ended December 31, 2015 when compared to 2014 as a result of lower average market prices for power and a 4.2% decrease in MWh sales. 36 Comparisons of kWh sales and operating revenues are shown below: Years Ended December 31: kWh sales (in thousands): Retail: Residential Commercial and industrial, small Commercial and industrial, large Sales to public authorities Total retail sales Wholesale: Sales for resale Off-system sales Total wholesale sales Total kWh sales Operating revenues (in thousands): Non-fuel base revenues: Retail: Residential Commercial and industrial, small Commercial and industrial, large Sales to public authorities $ Total retail non-fuel base revenues (1) Wholesale: Sales for resale Total non-fuel base revenues Fuel revenues: Recovered from customers during the period Under (over) collection of fuel (2) New Mexico fuel in base rates Total fuel revenues (3) Off-system sales: Fuel cost Shared margins Retained margins Total off-system sales Other (4) (5) Total operating revenues Average number of retail customers (6): Residential Commercial and industrial, small Commercial and industrial, large Sales to public authorities Total 2016 2015 Amount Percent Increase (Decrease) 2,805,789 2,403,447 1,030,745 1,572,510 7,812,491 62,086 1,927,508 1,989,594 9,802,085 2,771,138 2,384,514 1,062,662 1,585,568 7,803,882 63,347 2,500,947 2,564,294 10,368,176 $ 278,774 194,942 39,070 96,881 609,667 2,407 612,074 148,397 14,893 33,279 196,569 38,933 5,632 1,137 45,702 $ 246,265 187,436 40,411 91,244 565,356 2,455 567,811 127,765 (13,342) 72,129 186,552 52,406 11,048 1,362 64,816 32,591 886,936 $ 30,690 849,869 $ $ 362,138 41,014 49 5,303 408,504 356,969 40,250 49 5,250 402,518 34,651 18,933 (31,917) (13,058) 8,609 (1,261) (573,439) (574,700) (566,091) 32,509 7,506 (1,341) 5,637 44,311 (48) 44,263 20,632 28,235 (38,850) 10,017 (13,473) (5,416) (225) (19,114) 1,901 37,067 5,169 764 — 53 5,986 1.3% 0.8 (3.0) (0.8) 0.1 (2.0) (22.9) (22.4) (5.5) 13.2% 4.0 (3.3) 6.2 7.8 (2.0) 7.8 16.1 - (53.9) 5.4 (25.7) (49.0) (16.5) (29.5) 6.2 4.4 1.4% 1.9 - 1.0 1.5 ___________________________ (1) (2) Includes a $40.9 million increase resulting from the PUCT Final Order in 2016. Includes the portion of DOE refunds related to spent fuel storage of $1.6 million and $5.8 million in 2016 and 2015, respectively, that were credited to customers through the applicable fuel adjustment clauses. Includes deregulated Palo Verde Unit 3 revenues for the New Mexico jurisdiction of $8.7 million and $9.7 million in 2016 and 2015, respectively. Includes an Energy Efficiency Bonus of $0.5 million and $1.3 million in 2016 and 2015, respectively. Represents revenues with no related kWh sales and includes $1.5 million increase resulting from the PUCT Final Order in 2016. The number of retail customers presented is based on the number of service locations. (3) (4) (5) (6) 37 Years Ended December 31: kWh sales (in thousands): Retail: Residential Commercial and industrial, small Commercial and industrial, large Sales to public authorities Total retail sales Wholesale: Sales for resale Off-system sales Total wholesale sales Total kWh sales Operating revenues (in thousands): Non-fuel base revenues: Retail: Residential Commercial and industrial, small Commercial and industrial, large Sales to public authorities Total retail non-fuel base revenues $ Wholesale: Sales for resale Total non-fuel base revenues Fuel revenues: Recovered from customers during the period Under (over) collection of fuel (1) New Mexico fuel in base rates Total fuel revenues (2) Off-system sales: Fuel cost Shared margins Retained margins Total off-system sales Other (3) (4) Total operating revenues Average number of retail customers (5): Residential Commercial and industrial, small Commercial and industrial, large Sales to public authorities Total 2015 2014 Amount Percent Increase (Decrease) 2,771,138 2,384,514 1,062,662 1,585,568 7,803,882 2,640,535 2,357,846 1,064,475 1,562,784 7,625,640 63,347 2,500,947 2,564,294 10,368,176 61,729 2,609,769 2,671,498 10,297,138 $ 246,265 187,436 40,411 91,244 565,356 2,455 567,811 127,765 (13,342) 72,129 186,552 52,406 11,048 1,362 64,816 $ 234,371 185,388 39,239 92,066 551,064 2,277 553,341 161,052 3,110 71,614 235,776 74,716 21,117 2,147 97,980 30,690 849,869 $ 30,428 917,525 $ $ 356,969 40,250 49 5,250 402,518 352,277 39,600 49 5,088 397,014 130,603 26,668 (1,813) 22,784 178,242 1,618 (108,822) (107,204) 71,038 11,894 2,048 1,172 (822) 14,292 178 14,470 (33,287) (16,452) 515 (49,224) (22,310) (10,069) (785) (33,164) 262 (67,656) 4,692 650 — 162 5,504 4.9% 1.1 (0.2) 1.5 2.3 2.6 (4.2) (4.0) 0.7 5.1% 1.1 3.0 (0.9) 2.6 7.8 2.6 (20.7) - 0.7 (20.9) (29.9) (47.7) (36.6) (33.8) 0.9 (7.4) 1.3% 1.6 - 3.2 1.4 _______________________ (1) Includes the portion of DOE refund related to spent fuel storage of $5.8 million and $7.9 million in 2015 and 2014, respectively, that were credited to customers through the applicable fuel adjustment clauses. 2014 includes $2.2 million related to Palo Verde performance rewards, net. Includes deregulated Palo Verde Unit 3 revenues for the New Mexico jurisdiction of $9.7 million and $15.0 million in 2015 and 2014, respectively. Includes an Energy Efficiency Bonus of $1.3 million and $2.0 million in 2015 and 2014, respectively. Represents revenues with no related kWh sales. The number of retail customers presented is based on the number of service locations. (2) (3) (4) (5) 38 Energy expenses Our sources of energy include electricity generated from our nuclear, natural gas and coal generating plants and purchased power. After adding the new natural gas generating units (MPS Units 1 and 2) in March 2015 and (MPS Units 3 and 4) in May 2016 and September 2016, respectively, into the Company's system generating resources, Palo Verde represents approximately 30% of our available net generating capacity and approximately 58% of our Company-generated energy for the twelve months ended December 31, 2016. 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. Energy expenses decreased $8.5 million, or 3.5%, for the twelve months ended December 31, 2016 compared to the twelve months ended December 31, 2015, primarily due to (i) decreased natural gas costs of $10.6 million due to a 6.3% decrease in the MWhs generated with natural gas and (ii) decreased coal costs of $7.8 million as a result of the sale of our interest in Four Corners, a coal-fired generation station, on July 6, 2016. These decreases in energy expenses were partially offset by (i) increased total purchased power of $6.2 million due to a 11.6% increase in the MWhs purchased and (ii) increased nuclear fuel expense of $3.7 million due to a $4.6 million reduction in the 2016 DOE refund compared to 2015. Energy expenses decreased $73.9 million, or 23.4%, for the twelve months ended December 31, 2015 compared to 2014, primarily due to (i) decreased natural gas costs of $62.5 million due to a 32.0% decrease in the average price of natural gas, (ii) decreased total purchased power of $11.3 million due to a 18.7% decrease in the average price of total purchased power and (iii) decreased nuclear fuel expense of $1.2 million due to a 7.2% decrease in the cost of nuclear fuel consumed. The decrease in energy expense was partially offset by (i) a $2.1 million reduction in the 2015 DOE refund compared to 2014 and (ii) an increase in coal costs of $1.0 million due to a 10.3% increase in the MWhs generated with coal. The table below details the sources and costs of energy for 2016, 2015 and 2014. 2016 MWh Cost per MWh 2015 MWh Cost per MWh Cost (in thousands) 134,361 $ 13,913 40,126 (b) 188,400 $ 3,790,659 657,744 5,136,686 9,585,089 22,495 31,050 53,545 241,945 $ 277,241 1,113,705 1,390,946 10,976,035 35.45 21.15 9.06 20.32 81.14 27.88 38.50 22.63 Cost (in thousands) 123,806 $ 6,154 (a) 43,778 (b) 173,738 $ 3,550,904 175,258 5,093,844 8,820,006 Fuel Type Natural Gas Coal Nuclear Total Purchase Power: Photovoltaic Other Natural Gas Coal Nuclear Total Purchase Power: Photovoltaic Other Total purchased power Total energy $ 23,413 36,314 59,727 233,465 289,800 1,262,451 1,552,251 10,372,257 Fuel Type Cost 2014 MWh Cost per MWh (in thousands) 196,833 $ 12,883 41,289 (b) 251,005 $ 3,774,209 596,252 5,106,668 9,477,129 Total purchased power Total energy $ 19,575 45,229 64,804 315,809 227,979 1,162,511 1,390,490 10,867,619 34.87 35.11 8.94 19.90 80.79 28.76 38.48 22.68 52.15 21.61 9.76 27.39 85.86 39.80 47.35 29.94 _____________________ (a) The sale of our interest in Four Corners, a coal-fired generation station, closed on July 6, 2016. (b) Costs includes a DOE refund related to spent fuel storage of $1.8 million, $6.4 million, and $8.5 million recorded in 2016, 2015, and 2014, respectively. Cost per MWh excludes this settlement. 39 Other operations expense Other operations expense decreased $0.9 million, or 0.4%, in 2016 compared to 2015, primarily due to (i) a $2.7 million decrease in pension and benefits costs due to an amendment to the other post-retirement benefit plan and changes in actuarial assumptions used to calculate expenses for the post-retirement benefit plans, partially offset by higher medical and other employee benefit costs, (ii) decreased operations expense of $0.9 million at our fossil-fuel generating plants, primarily due to lower operating costs as a result of the sale of our interest in Four Corners offset by increased operating expenses at the MPS, and (iii) decreased other administrative and general expenses of $0.5 million. These decreases were partially offset by (i) a $2.3 million increase in regulatory expenses, primarily related to the 2015 New Mexico and Texas rate cases being expensed, and (ii) increased transmission and distribution expenses of $0.8 million. Other operations expense increased $4.1 million, or 1.7%, in 2015 compared to 2014 primarily due to (i) a $4.0 million increase in other operations payroll costs including a $1.5 million increase in employee incentive compensation; (ii) increased pension and benefits costs due to changes in actuarial assumptions used to calculate expenses for the post-retirement benefit plan; (iii) a $1.7 million increase in operations expenses at our fossil-fuel generating plants primarily due to expenses at our MPS with no comparable expenses during 2014 and (iv) a $1.5 million increase in transmission and distribution expenses related to wheeling expense and system support and improvements. These increases were partially offset by (i) a $1.9 million decrease in outside services expenses and (ii) a $1.4 million decrease in operations expense at Palo Verde. Maintenance expense Maintenance expense increased $1.5 million, or 2.3%, in 2016 compared to 2015, primarily due to an increase in the level of maintenance at Rio Grande and a planned outage at Four Corners, which was partially offset by a decrease in maintenance at Newman. Maintenance expense decreased $0.4 million, or 0.6%, in 2015 compared to 2014, primarily due to a decrease in the level of maintenance at our Rio Grande and Four Corners generating plants, which was partially offset by maintenance at our MPS with no comparable expenses during 2014. Depreciation and amortization expense Depreciation and amortization expense decreased $5.5 million or 6.1%, in 2016 compared to 2015, primarily due to reductions of approximately $10.9 million resulting from changes in depreciation rates approved in the PUCT Final Order and the NMPRC Final Order, and the sale of the Company's interest in Four Corners in July 2016. These decreases were partially offset by an increase in plant, primarily due to MPS Units 1 and 2 and the EOC being placed in service in March 2015, and MPS Units 3 and 4 being placed in service in May 2016 and September 2016, respectively. Depreciation and amortization expense increased $6.5 million, or 7.8%, in 2015 compared to 2014, primarily due to the increases in depreciable plant balances, including MPS Units 1 and 2 and the EOC, which were placed in service during the first quarter of 2015, partially offset by an increase in the estimated useful lives of certain large intangible software systems effective July 2015 in the amount of $1.8 million. Taxes other than income taxes Taxes other than income taxes increased $1.8 million, or 2.8%, in 2016 compared to 2015, 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 in Texas. These increases were partially offset by decreased property taxes in Arizona due to decreased property values. Taxes other than income taxes increased $1.0 million, or 1.6%, in 2015 compared to 2014, primarily due to (i) higher property tax values and assessment rates and (ii) additional payroll taxes. Other income (deductions) Other income (deductions) decreased $7.2 million, or 27.8%, in 2016 compared to 2015, primarily due to (i) decreased allowance for equity funds used during construction ("AEFUDC") resulting from lower average balances of construction work in progress ("CWIP") and a reduction in the AEFUDC rate, and (ii) decreased investment and interest income due to lower realized gains from our Palo Verde decommissioning trust fund equity portfolio. Other income (deductions) decreased $2.3 million, or 8.1%, in 2015 compared to 2014, primarily due to (i) decreased AEFUDC resulting from lower average balances of CWIP and a reduction in the AEFUDC rate and (ii) higher gains recognized on the sales of land in 2014 compared to 2015. This decrease was partially offset by increased investment and interest income due to further diversification and re-balancing of our Palo Verde decommissioning trust fund equity portfolio. 40 Interest charges (credits) Interest charges (credits) increased by $7.6 million, or 13.8%, in 2016 compared to 2015, primarily due to interest expense on the $150.0 million aggregate principal amount of 5.00% Senior Notes due 2044 issued in March 2016 and decreased allowance for borrowed funds used during construction ("ABFUDC") as a result of lower average balances of CWIP and a reduction in the ABFUDC rate. Interest charges (credits) increased by $8.4 million, or 18.0%, in 2015 compared to 2014 primarily due to interest expense on the $150.0 million aggregate principal amount of 5.00% Senior Notes due 2044 issued in December 2014 and decreased ABFUDC as a result of lower balances of CWIP and a reduction in the ABFUDC rate. Income tax expense Income tax expense increased by $19.0 million, or 54.5%, in 2016 compared to 2015, primarily due to (i) an increase in the pre-tax income and (ii) an increase in state income taxes due to normalization as discussed in Note J of the Notes to Financial Statements and decreases in decommissioning trust income, which is taxed at a lower rate. Income tax expense decreased by $6.2 million, or 15.1%, in 2015 compared to 2014, primarily due to (i) a decrease in the pre-tax income and (ii) a decrease in state income taxes. New accounting standards In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) to provide a framework that replaces the existing revenue recognition guidance, and 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. More specifically, the standard requires entities to recognize revenue through the application of a five- step model, which includes the: (i) identification of the contract; (ii) identification of the performance obligations; (iii) determination of the transaction price; (iv) allocation of the transaction price to the performance obligations; and (v) the recognition of revenue as the entity satisfies the performance obligations. Early adoption of ASU 2014-09 is permitted after December 15, 2016, however, we plan to adopt the new standard for reporting periods beginning after December 15, 2017. Under the new standard, companies may use either of the following transition methods: (i) a full retrospective approach reflecting the application of the standard in each prior reporting period with the option to elect certain practical expedients, or (ii) a modified retrospective approach with the cumulative effect of initially adopting ASU 2014-09 recognized at the date of adoption (which includes additional footnote disclosures). We have not concluded which transition method we will elect but we currently anticipate using the modified retrospective approach. We are currently in the process of evaluating the impact of the new standard on our various revenue and cash flow streams, including the evaluation of the impact, if any, on changes to business processes, systems and controls to support recognition and disclosure under the new guidance. Tariff sales to customers are determined to be in the scope of the new standard and represent a significant portion of our total operating revenues. We have not completed our final evaluation of tariff sales under the new guidance but currently we do not anticipate that ASU 2014-09 will have a material impact on our revenue recognition for such sales. We are still considering the impacts of the guidance on several industry-related accounting issues, including the accounting for contributions in aid of construction ("CIAC"), assessing the collectability criterion and the presentation of revenues associated with alternative revenue programs. Our initial assessment may change as we execute our implementation plan and new guidance is provided by the American Institute of Certified Public Accountants Power and Utilities Industry Task Force. In January 2016, the FASB issued ASU 2016-01, Financial Instruments-Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Liabilities to enhance the reporting model for financial instruments by addressing certain aspects of recognition, measurement, presentation, and disclosure. ASU 2016-01 generally requires entities to measure equity investments that do not result in consolidation and are not accounted for under the equity method at fair value and recognize any changes in fair value in net income. The guidance for classifying and measuring investments in debt securities and loans is not changed by this ASU, but requires entities to record changes in other comprehensive income. Financial assets and financial liabilities must be separately presented by measurement category on the balance sheet or in the accompanying notes to the financial statements. ASU 2016-01 clarifies the need for a valuation allowance on a deferred tax asset related to available-for-sale securities in combination with the entity's other deferred tax assets. The provisions of this ASU become effective for public companies for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. Upon adoption of the new standard, we expect to record the cumulative effects as of January 1, 2018 which will result in an adjustment to accumulated other comprehensive income (losses) and retained earnings for unrealized gains (losses) related to equity securities owned by us. Had we been required to adopt the new standard at January 1, 2016, accumulated other comprehensive income would decrease by $28.8 million and retained earnings would increase by a corresponding amount. Furthermore, we would report for the year ended 41 December 31, 2016 an increase in investment income of $1.2 million, an increase in income tax expense of $0.2 million and a decrease in other comprehensive income of $1.0 million. We continue to assess the future impact of this ASU. 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 leases guidance for capital leases and operating leases. The impact of leases reported in our operating results and statement of cash flows are 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 leases are recorded in regard to financial position 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. Implementation of the standard for public companies will be required for annual reporting periods beginning after December 15, 2018 and interim periods within that reporting period. Early adoption of ASU 2016-02 is permitted for all entities, however, we plan to adopt the new standard for reporting periods beginning after December 15, 2018. Adoption of the new lease accounting standard will require us to apply the new standard to the earliest period using a modified retrospective approach. We are currently in the process of evaluating the impact of the new standard, including the evaluation of the impact, if any, on changes to business processes, systems and controls to support recognition and disclosure under the new guidance, however, at this time we are unable to determine the impact this standard will have on the financial statements and related disclosures. 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. We will adopt the new standard effective January 1, 2017 and do not expect the effect of the adoption to be material to our financial condition, results of operations or cash flows. The cumulative effect of the adoption of the new standard will be to increase net operating loss carryforward deferred tax assets and retained earnings by approximately $0.2 million on January 1, 2017. We also expect to continue to account for our outstanding stock awards based on the equity method and therefore do not anticipate any changes in reporting related compensation expense. In June 2016, the FASB issued ASU 2016-13, Financial Instruments - Credit Losses (Topic 326) ("ASU 2016-13"). ASU 2016-13 changes how companies measure and recognize credit impairment for many financial assets. The new current 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. For public business entities, the provisions of ASU 2016-13 are effective for fiscal years and interim periods within that reporting period beginning after December 15, 2019. Early implementation is permitted as of the fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. 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. We are currently assessing the future impact of ASU 2016-13. 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 new guidance addresses the following classification issues: debt prepayment or debt extinguishment costs; settlement of zero-coupon bonds; contingent consideration payments made after a business combination; proceeds from the settlement of insurance claims; proceeds from the settlement of corporate-owned life insurance policies, including bank-owned life insurance policies; distributions received from equity method investees; beneficial interests in securitization transactions; and separately identifiable cash flows and application of the predominance principle. For public business entities, the provisions of ASU 2016-15 are effective for fiscal years and interim periods within that reporting period beginning after December 15, 2017. Early adoption is permitted, including adoption in an interim period. If an entity elects early adoption of ASU 2016-15 in an interim period, adjustments should be reflected as of the beginning of the fiscal year that includes that interim period. An entity that elects early adoption must adopt all of the amendments in the same period. ASU 2016-15 will be applied using a retrospective transition method to each period presented. If it is impracticable to apply ASU 2016-15 retrospectively for some of the issues, the amendments for those issues may be applied prospectively as of the earliest date practicable. We are currently assessing the future impact of this ASU. In December 2016, the FASB issued ASU 2016-19, Technical Corrections and Improvements, which amends a number of Topics in the FASB ASC. This ASU is part of an ongoing FASB project to facilitate Codification updates for non-substantive technical corrections, clarifications, and improvements that are not expected to have a significant effect on accounting practice or create a significant administrative cost to most entities. Most of the amendments are effective upon issuance of ASU 2016-19 while certain amendments that require transition guidance are effective for us beginning January 1, 2017. We believe we are in 42 compliance with those amendments that are effective immediately and that are applicable to us. We have not completed our evaluation of the new standard for amendments that require transition guidance. Inflation For the last several years, inflation has been relatively low and, therefore, has had little impact on our results of operations and financial condition. Liquidity and Capital Resources In March 2016, we issued $150.0 million aggregate principal amount of 5.00% Senior Notes due December 1, 2044 to repay outstanding short-term borrowings under our RCF used for working capital and general corporate purposes, which may include funding capital expenditures. Despite such issuances of senior notes, we continue to maintain a strong balance of common stock equity in our capital structure, which supports our bond ratings, allowing us to obtain financing from the capital markets at a reasonable cost. At December 31, 2016, our capital structure, including common stock, long-term debt, current maturities of long- term debt, and short-term borrowings under the RCF, consisted of 44.1% common stock equity and 55.9% debt. As of December 31, 2016, we had a balance of $8.4 million of cash and cash equivalents. Based on current projections, we believe that we will have adequate liquidity through our current cash balances, cash from operations and available borrowings under our RCF to meet all of our anticipated cash requirements for the next twelve months, including the upcoming maturities of long term debt. 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, payment of our $50.0 million Series B 4.47% Senior Notes which mature in August 2017 and payment or remarketing of $33.3 million 2012 Series A 1.875% Pollution Control Bonds which are subject to mandatory tender for purchase in September 2017. Capital Requirements. During the twelve months ended December 31, 2016, our capital requirements primarily consisted of expenditures for the construction and purchase of electric utility plant, cash dividend payments, and purchases of nuclear fuel. Projected utility construction expenditures are to add new generation, expand and update our transmission and distribution systems, and make capital improvements and replacements at Palo Verde and other generating facilities. On May 3, 2016 and September 15, 2016, we placed into commercial operation MPS Units 3 and 4, respectively, and the related common facilities and transmission systems at a combined cost of approximately $160.5 million, including AFUDC, for the two units. Estimated cash construction expenditures for all capital projects for 2017 are expected to be approximately $215 million. See Part I, Item 1, "Business – Construction Program." Cash capital expenditures for new electric plant were $225.4 million in the twelve months ended December 31, 2016 compared to $281.5 million in the twelve months ended December 31, 2015. Capital requirements for purchases of nuclear fuel were $42.4 million for the twelve months ended December 31, 2016, as compared to $42.0 million for the twelve months ended December 31, 2015. On December 30, 2016, we paid a quarterly cash dividend of $0.31 per share, or $12.6 million, to shareholders of record as of the close of business on December 14, 2016. We paid a total of $49.6 million in cash dividends during the twelve months ended December 31, 2016. On January 26, 2017, our Board of Directors declared a quarterly cash dividend of $0.31 per share payable on March 31, 2017 to shareholders of record at the close of business on March 17, 2017 which will require cash of $12.5 million. Typically, the Board of Directors reviews the Company's 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 2017, 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, 2016. As of December 31, 2016, 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. We primarily utilize the distribution of dividends to maintain a balanced capital structure and supplement this effort with share repurchases when appropriate. Our liquidity needs can fluctuate quickly based on fuel prices and other factors and we are continuing to make investments in new electric plant and other assets in order to reliably serve our customers. Our cash requirements for federal and state income taxes vary from year to year based on taxable income, which is influenced by the timing of revenues and expenses recognized for income tax purposes. Due to net operating loss carryfowards resulting from accelerated depreciation deductions, income tax payments are expected to be minimal in 2017. 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 $10.9 million to our retirement plans during both the twelve months 43 ended December 31, 2016 and 2015, respectively. We contributed $1.7 million and $0.5 million to our other post-retirement benefit plans during the twelve months ended December 31, 2016 and 2015, respectively. We contributed $4.5 million to our decommissioning trust funds in both 2016 and 2015. 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. In 2010, we and RGRT, a Texas grantor trust through which we finance our portion of fuel for Palo Verde, entered into a note purchase agreement with various institutional purchasers. Under the terms of the agreement, RGRT sold to the purchasers $110.0 million aggregate principal amount of senior notes. In August 2015, $15.0 million of these senior notes matured and were paid with borrowings under the RCF. In August 2016, $50.0 million of these senior notes were reclassified to current maturities of long-term debt on our Balance Sheet, as they will mature in August 2017. Capital Resources. Cash provided by operations, $231.2 million for the twelve months ended December 31, 2016 and $246.7 million for the twelve months ended December 31, 2015, is a significant source for funding capital requirements. The primary factors affecting the change in cash flows from operations were increases in net under-collection of fuel revenues and accounts receivable. Offsetting the decreases in cash flows from operations were increased revenues due to the PUCT Final Order and the NMPRC Final Order and increases in deferred income taxes. 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 customer. We recover actual fuel costs from customers through fuel adjustment mechanisms in Texas and New Mexico, and from our sales for resale customer. We record deferred fuel revenues for the under-recovery or over-recovery of fuel costs until they can be recovered from or refunded to customers. In Texas, fuel costs are recovered through a fixed fuel factor. 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 November 30, 2016, we filed a request to increase our Texas fixed fuel factor by approximately 28.8% to reflect increasing natural gas costs. This increase was effective with January 2017 billings. During the twelve months ended December 31, 2016, we had under-recoveries of fuel costs of $14.9 million compared to over-recoveries of fuel costs of $13.3 million during the twelve months ended December 31, 2015. At December 31, 2016, we had a net fuel under-recovery balance of $10.9 million, including an under-recovery of $11.1 million in the Texas jurisdiction offset by an over-recovery of $0.2 million the New Mexico jurisdiction. We maintain the RCF for working capital and general corporate purposes and financing nuclear fuel through RGRT. RGRT, the trust through which we finance our portion of nuclear fuel for Palo Verde, is consolidated in our financial statements. On January 9, 2017, we exercised our option to extend the maturity of the RCF by one year to January 14, 2020 and to increase the size of the facility by $50.0 million to $350.0 million. We still have the option to extend the facility by one additional year to January 2021 and to increase the RCF by up to $50.0 million (up to a total of $400.0 million) upon the satisfaction of certain conditions including obtaining commitments from lenders or third party financial institutions. Additionally, we agreed to reduce the letters of credit commitment under the RCF to $50.0 million from a total commitment of $350.0 million. The total amount borrowed for nuclear fuel by RGRT, excluding debt issuance costs, was $132.6 million at December 31, 2016, of which $37.6 million had been borrowed under the RCF, and $95.0 million was borrowed through senior notes. At December 31, 2015, the total amounts borrowed for nuclear fuel by RGRT, excluding debt issuance costs, were $128.7 million of which $33.7 million had been borrowed under the RCF and $95.0 million was borrowed through senior notes. Interest costs on borrowings to finance nuclear fuel are accumulated by RGRT and charged to us as fuel is consumed and recovered from customers through fuel recovery charges. The outstanding balance for working capital and general corporate purposes was $44.0 million at December 31, 2016 and $108.0 million at December 31, 2015. Total aggregate borrowings under the RCF as of December 31, 2016 were $81.6 million, with available borrowing capacity of $267.9 million thereunder, after giving consideration to the $50.0 million increase on January 9, 2017. We received approval from the NMPRC on October 7, 2015 and from the FERC on October 19, 2015 to issue up to $310.0 million in new long-term debt and to guarantee the issuance of up to $65.0 million of new debt by RGRT to finance future purchases of nuclear fuel and to refinance existing nuclear fuel debt obligations. We also requested approval from the FERC to continue to utilize our existing RCF without change from the FERC’s previously approved authorization. The FERC authorization is effective from November 15, 2015 through November 15, 2017. The approvals granted in these cases supersede prior approvals. Under this authorization, on March 24, 2016, we issued $150.0 million aggregate principal amount of 5.00% Senior Notes due December 1, 2044. The proceeds from the issuance of these senior notes, 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 effective interest rate for these senior notes is approximately 4.77%. The net proceeds from the sale of these senior notes were used to repay outstanding 44 short-term borrowings under the RCF. These senior notes constitute an additional issuance of our 5.00% Senior Notes due 2044, of which $150.0 million aggregate principal amount was previously issued on December 1, 2014, for a total principal amount currently outstanding of $300.0 million. 45 Contractual Obligations. Our contractual obligations as of December 31, 2016 are as follows (in thousands): Revolving credit facility (4) 83,075 83,075 Payments due by period Total 2017 2018 and 2019 2020 and 2021 2022 and Beyond $ 2,135,575 $ 55,200 $ 110,400 $ 110,400 $ 1,859,575 434,253 106,307 43,675 54,503 19,918 4,536 19,918 47,268 350,742 — — — — — 61,261 15,454 165,915 25,427 — — — — — — 58,538 22,558 — — 12,726 12,726 335,992 84,960 11,498 4,500 9,940 50,278 21,521 11,498 4,500 808 Long-term debt (including interest): Senior notes (1) Pollution control bonds (2) RGRT senior notes (3) Financing obligations (including interest): Purchase obligations: Power contracts Fuel contracts: Gas (5) Nuclear fuel (6) Retirement plans and other post-retirement benefits (7) Nuclear Decommissioning Trust Funds (8) Operating leases (9) Total _____________________ (1) $ 3,218,826 $ 337,784 $ 217,278 $ 255,527 $ 2,408,237 1,328 1,226 6,578 We have four 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. We have four series of pollution control bonds that are scheduled for remarketing and/or mandatory tender, one in 2017, two in 2040, and one in 2042. In 2010, the Company and RGRT entered into a note purchase agreement for $110.0 million aggregate principal amount of senior notes consisting of: (a) $15.0 million aggregate principal amount of 3.67% RGRT Senior Notes, Series A, which matured and were repaid on August 15, 2015; (b) $50.0 million aggregate principal amount of 4.47% RGRT Senior Notes, Series B, due August 15, 2017; and (c) $45.0 million aggregate principal amount of 5.04% RGRT Senior Notes, Series C, due August 15, 2020. This reflects obligations outstanding under the $300.0 million RCF. At December 31, 2016, $44.0 million was borrowed for working capital and general corporate purposes and $37.6 million was borrowed by RGRT for nuclear fuel. This balance includes interest based on actual interest rates at the end of 2016 and assumes this amount will be outstanding for the entire year of 2017. Amount is based on the minimum volumes per the contract and market and/or contract price at the end of 2016. Gas obligation includes a gas storage contract and a gas transportation contract. 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 2016. 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 2017. We have no minimum cash contractual funding requirement related to our retirement income plan or other post-retirement benefits for 2017. However, we are subject to minimum funding requirements of ERISA. We also may decide to fund at higher levels and expect to contribute $11.5 million to our retirement plans in 2017, as disclosed in Part II, Item 8, Financial Statements and Supplementary Data, Note M. Minimum funding requirements for 2018 and beyond are not included due to the uncertainty of the applicable interest rates and the related return on assets. This obligation is based on our anticipated contributions in 2017. We have no minimum funding obligation in either the Texas or New Mexico jurisdiction effective February 1, 2016 with PUCT Docket No. 44941 and July 1, 2016 with NMPRC Case No. 15-00127-UT, respectively. However, we continued to fund at the same funding levels of $0.4 million (2) (3) (4) (5) (6) (7) (8) 46 (9) per month in 2016. We expect our funding requirements to change in the future based on amounts requested in our upcoming rate filings in both jurisdictions. 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 four 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. 47 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. Our decommissioning trust funds consist of equity securities and fixed income instruments and are carried at fair value. We face interest rate risk on the fixed income instruments, which consist primarily of municipal, federal and corporate bonds and which were valued at $119.9 million and $113.3 million as of December 31, 2016 and 2015, respectively. A hypothetical 10% increase in interest rates would reduce the fair values of these funds by $1.4 million and $1.2 million at December 31, 2016 and 2015, respectively. Equity Price Risk Our decommissioning trust funds include marketable equity securities of approximately $129.8 million and $117.5 million at December 31, 2016 and 2015, respectively. A hypothetical 20% decrease in equity prices would have reduced the fair values of these funds by $26.0 million and $23.5 million based on their fair values at December 31, 2016 and 2015, respectively. Declines in market prices could require that additional amounts be contributed to our nuclear decommissioning trusts to maintain minimum funding requirements. We do not expect to expend monies held in trust 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, 2017, 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. 48 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, 2016. 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, 2016, 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 51 of this report. 49  Item 8. Financial Statements and Supplementary Data INDEX TO FINANCIAL STATEMENTS Report of Independent Registered Public Accounting Firm Balance Sheets as of December 31, 2016 and 2015 Statements of Operations for the years ended December 31, 2016, 2015, 2014 Statements of Comprehensive Operations for the years ended December 31, 2016, 2015, and 2014 Statements of Changes in Common Stock Equity for the years ended December 31, 2016, 2015, 2014 Statements of Cash Flows for the years ended December 31, 2016, 2015, 2014 Notes to Financial Statements Page 51 52 54 55 56 57 58 50 Report of Independent Registered Public Accounting Firm The Board of Directors and Stockholders El Paso Electric Company: We have audited the accompanying balance sheets of El Paso Electric Company (the Company) as of December 31, 2016 and 2015, 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, 2016. We also have audited El Paso Electric Company’s internal control over financial reporting as of December 31, 2016, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). El Paso Electric 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 these financial statements and an opinion on the Company’s internal control over financial reporting based on our audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions. A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of El Paso Electric Company as of December 31, 2016 and 2015, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2016, in conformity with U.S. generally accepted accounting principles. Also in our opinion, El Paso Electric Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2016, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). /s/ KPMG LLP Houston, Texas February 24, 2017 51 EL PASO ELECTRIC COMPANY BALANCE SHEETS ASSETS (In thousands) Utility plant: Electric plant in service Less accumulated depreciation and amortization Net plant in service Construction work in progress Nuclear fuel; includes fuel in process of $57,315 and $51,854, respectively Less accumulated amortization Net nuclear fuel Net utility plant Current assets: Cash and cash equivalents Accounts receivable, principally trade, net of allowance for doubtful accounts of $2,156 and $2,046, respectively Inventories, at cost Under-collection of fuel revenues Prepayments and other Total current assets Deferred charges and other assets: Decommissioning trust funds Regulatory assets Other Total deferred charges and other assets Total assets See accompanying notes to financial statements. December 31, 2016 2015 $ 3,791,566 (1,244,332) 2,547,234 154,738 $ 3,616,301 (1,329,843) 2,286,458 293,796 194,842 (75,602) 119,240 190,282 (75,031) 115,251 2,821,212 2,695,505 8,420 88,452 47,216 11,123 8,988 8,149 66,326 48,697 — 9,872 164,199 133,044 255,708 118,861 16,298 390,867 239,035 115,127 17,896 372,058 $ 3,376,278 $ 3,200,607 52 EL PASO ELECTRIC COMPANY BALANCE SHEETS (Continued) Capitalization: CAPITALIZATION AND LIABILITIES (In thousands except for share data) Common stock, stated value $1 per share, 100,000,000 shares authorized, 65,685,615 and 65,709,819 shares issued, and 137,017 and 118,834 restricted shares, respectively Capital in excess of stated value Retained earnings Accumulated other comprehensive loss, net of tax $ Treasury stock, 25,304,914 and 25,384,834 shares, respectively, at cost Common stock equity Long-term debt, net of current portion Total capitalization Current liabilities: Current maturities of long-term debt Short-term borrowings under the revolving credit facility Accounts payable, principally trade Taxes accrued Interest accrued Over-collection of fuel revenues Other Total current liabilities Deferred credits and other liabilities: Accumulated deferred income taxes Accrued pension liability Accrued post-retirement benefit liability Asset retirement obligation Regulatory liabilities Other Total deferred credits and other liabilities Commitments and contingencies December 31, 2016 2015 $ 65,823 322,643 1,114,561 (7,116) 1,495,911 (421,515) 1,074,396 1,195,513 2,269,909 65,829 320,073 1,067,396 (13,914) 1,439,384 (422,846) 1,016,538 1,122,660 2,139,198 83,143 81,574 62,953 32,488 13,287 255 29,709 303,409 555,066 92,768 34,400 81,800 18,435 20,491 802,960 — 141,738 59,978 30,351 12,649 4,023 28,325 277,064 495,237 90,527 54,553 81,621 24,303 38,104 784,345 Total capitalization and liabilities $ 3,376,278 $ 3,200,607 See accompanying notes to financial statements. 53 EL PASO ELECTRIC COMPANY STATEMENTS OF OPERATIONS (In thousands except for share data) Years Ended December 31, 2016 2015 2014 $ 886,936 $ 849,869 $ 917,525 173,738 59,727 233,465 653,471 188,400 53,545 241,945 607,924 251,005 64,804 315,809 601,716 242,014 242,950 238,832 66,746 84,317 65,533 458,610 194,861 7,023 14,083 1,292 (3,699) 18,699 71,544 1,303 (4,990) (4,983) 62,874 150,686 53,918 96,768 2.39 2.39 1.225 $ $ $ $ 65,223 89,824 63,736 461,733 146,191 10,639 17,508 2,062 (4,328) 25,881 65,851 1,313 (4,968) (6,937) 55,259 116,813 34,895 81,918 2.03 2.03 1.165 $ $ $ $ 65,629 83,342 62,750 450,553 151,163 14,662 13,633 4,075 (4,199) 28,171 59,028 1,250 (5,092) (8,368) 46,818 132,516 41,088 91,428 2.27 2.27 1.105 40,350,688 40,274,986 40,190,991 40,408,033 40,308,562 40,211,717 $ $ $ $ Operating revenues Energy expenses: Fuel Purchased and interchanged power Operating revenues net of energy expenses Other operating expenses: Other operations Maintenance Depreciation and amortization Taxes other than income taxes Operating income Other income (deductions): Allowance for equity funds used during construction Investment and interest income, net Miscellaneous non-operating income Miscellaneous non-operating deductions Interest charges (credits): Interest on long-term debt and revolving credit facility Other interest Capitalized interest Allowance for borrowed funds used during construction Income before income taxes Income tax expense Net income Basic earnings per share Diluted earnings per share Dividends declared per share of common stock Weighted average number of shares outstanding Weighted average number of shares and dilutive potential shares outstanding See accompanying notes to financial statements. 54 EL PASO ELECTRIC COMPANY STATEMENTS OF COMPREHENSIVE OPERATIONS (In thousands) Net income Other comprehensive income (loss): Unrecognized pension and post-retirement benefit costs: Net gain (loss) arising during period Prior service benefit Reclassification adjustments included in net income for amortization of: Prior service benefit Net loss Net unrealized gains/losses on marketable securities: Net holding gains (losses) arising during period Reclassification adjustments for net gains included in net income Net losses on cash flow hedges: Reclassification adjustment for interest expense included in net income Total other comprehensive income (loss) before income taxes Income tax benefit (expense) related to items of other comprehensive income (loss): Unrecognized pension and post-retirement benefit costs Net unrealized (gains) losses on marketable securities Losses on cash flow hedges Total income tax benefit (expense) Other comprehensive income (loss), net of tax Comprehensive income See accompanying notes to financial statements. Years Ended December 31, 2016 2015 2014 $ 96,768 $ 81,918 $ 91,428 (20,053) 32,697 5,429 824 (54,328) 34,200 (7,407) 4,965 8,444 (7,640) 498 11,504 (4,261) (106) (339) (4,706) 6,798 $ 103,566 $ (6,574) 8,622 (2,906) (11,114) (7,659) 6,182 10,827 (7,350) 467 (5,252) 438 (17,690) (3,286) 2,828 (203) (661) (5,913) 76,005 $ 8,051 (760) (214) 7,077 (10,613) 80,815 55 EL PASO ELECTRIC COMPANY STATEMENTS OF CHANGES IN COMMON STOCK EQUITY (In thousands except for share data) Common Stock Shares 65,759,625 Amount $ 65,760 Capital in Excess of Stated Value 314,443 $ Accumulated Other Comprehensive Income (Loss), Net of Tax Retained Earnings $ 985,665 $ 2,612 103,672 (4,696) (19,162) 10,104 104 (5) (19) 10 4,175 (183) (302) 382 Treasury Stock Shares 25,492,919 $ Amount (424,647) $ Common Stock Equity 943,833 Balances at December 31, 2013 Restricted common stock grants and deferred compensation Stock awards withheld for taxes Forfeited restricted common stock Deferred taxes on stock incentive plan Compensation paid in shares Net income Other comprehensive income (loss) Dividends declared 4,279 (188) (19) (302) 392 91,428 (10,613) (44,556) 984,254 3,829 (571) (26) (475) 581 81,918 (5,913) (47,059) 1,016,538 Balances at December 31, 2014 65,849,543 65,850 318,515 Restricted common stock grants and deferred compensation Stock awards withheld for taxes Forfeited restricted common stock Deferred taxes on stock incentive plan Compensation paid in shares Net income Other comprehensive income (loss) Dividends declared 6,356 (15,031) (12,215) 6 (15) (12) 2,266 (556) (475) 323 Balances at December 31, 2015 65,828,653 65,829 320,073 91,428 (44,556) 1,032,537 81,918 (47,059) 1,067,396 (10,613) (8,001) 25,492,919 (424,647) (93,455) 1,557 871 (15,501) (14) 258 (5,913) (13,914) 25,384,834 (422,846) Restricted common stock grants and deferred compensation Stock awards withheld for taxes Forfeited restricted common stock Deferred taxes on stock incentive plan Compensation paid in shares Net income Other comprehensive income (loss) Dividends declared (5,723) (298) (6) 3,017 (261) (364) 178 (74,181) 197 (5,936) 96,768 (49,603) $ 1,114,561 $ 6,798 (7,116) 25,304,914 $ (3) 1,235 4,252 (267) (3) (364) 277 96,768 6,798 (49,603) (421,515) $ 1,074,396 99 Balances at December 31, 2016 65,822,632 $ 65,823 $ 322,643 See accompanying notes to financial statements. 56 EL PASO ELECTRIC COMPANY STATEMENTS OF CASH FLOWS (In thousands) Years Ended December 31, 2016 2015 2014 $ 96,768 $ 81,918 $ 91,428 84,317 43,748 50,510 (7,023) 17,295 (545) (7,640) 1,279 (17,511) 265 (14,891) (1,184) (2,140) 1,945 2,022 (16,065) 231,150 89,824 43,099 30,846 (10,639) 17,707 (658) (11,114) 517 4,839 (2,859) 13,344 (3,984) (11,235) 4,512 3,719 (3,165) 246,671 83,342 43,864 39,129 (14,662) 18,380 (2,092) (7,350) (93) (5,815) (786) (3,121) (2,750) 9,684 (2,209) 1,198 (4,807) 243,340 (225,361) (42,383) (281,458) (41,966) (277,078) (37,877) (12,006) (4,990) 7,023 (99,497) 91,268 4,841 5,373 (275,732) (17,576) (4,968) 10,639 (110,223) 102,567 721 (470) (342,734) (23,030) (5,092) 14,662 (117,675) 108,311 2,395 4,192 (331,192) (49,603) (47,059) (44,556) 355,607 (415,771) — 157,052 (2,432) 44,853 271 8,149 344,398 (217,192) (15,000) — (1,439) 63,708 (32,355) 40,504 $ 8,420 $ 8,149 $ 231,399 (231,219) — 149,468 (2,328) 102,764 14,912 25,592 40,504 Cash Flows From Operating Activities: Net income Adjustments to reconcile net income to net cash provided by operating activities: Depreciation and amortization of electric plant in service Amortization of nuclear fuel Deferred income taxes, net Allowance for equity funds used during construction Other amortization and accretion Gain on sale of property, plant and equipment Net gains on sale of decommissioning trust funds Other operating activities Change in: Accounts receivable Inventories Net over-collection (under-collection) of fuel revenues Prepayments and other Accounts payable Taxes accrued Other current liabilities Deferred charges and credits Net cash provided by operating activities Cash Flows From Investing Activities: Cash additions to utility property, plant and equipment Cash additions to nuclear fuel Capitalized interest and AFUDC: Utility property, plant and equipment Nuclear fuel Allowance for equity funds used during construction Decommissioning trust funds: Purchases, including funding of $4.5 million Sales and maturities Proceeds from sale of property, plant and equipment Other investing activities Net cash used for investing activities Cash Flows From Financing Activities: Dividends paid Borrowings under the revolving credit facility: Proceeds Payments Payment on maturing RGRT senior notes Proceeds from issuance of senior notes Other financing activities Net cash provided by financing activities Net increase (decrease) in cash and cash equivalents Cash and cash equivalents at beginning of period Cash and cash equivalents at end of period See accompanying notes to financial statements. 57 INDEX TO NOTES TO FINANCIAL STATEMENTS Note A. Summary of Significant Accounting Policies Note B. New Accounting Standards Note C. Regulation Note D. Regulatory Assets and Liabilities Note E. Utility Plant, Palo Verde and Other Jointly-Owned Utility Plant Note F. Accounting for Asset Retirement Obligations Note G. Common Stock Note H. Accumulated Other Comprehensive Income (Loss) Note I. Long-Term Debt and Financing Obligations Note J. Income Taxes Note K. Commitments, Contingencies and Uncertainties Note L. Litigation Note M. Employee Benefits Note N. Franchises and Significant Customers Note O. Financial Instruments and Investments Note P. Supplemental Statements of Cash Flow Disclosures Note Q. Selected Quarterly Financial Data (Unaudited) Page 59 62 63 68 69 72 73 78 80 82 85 87 88 101 102 107 108 58 EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS A. Summary of Significant Accounting Policies General. El Paso Electric Company is a public utility engaged in the generation, transmission and distribution of electricity in an area of approximately 10,000 square miles in west Texas and southern New Mexico. 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 (the "FERC"). Use of Estimates. The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. 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 (the "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 recoverable costs as either assets or liabilities on a utility’s balance sheet if the regulator provides assurance that these costs will be charged to and collected from the utility’s customers (or has already permitted such cost recovery) or will be credited or refunded to the utility’s customers. The resulting regulatory assets or liabilities are amortized in subsequent periods based upon the respective amortization periods reflected in a utility’s regulated rates. See Part II, Item 8, Financial Statements and Supplementary Data, Note D. 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 2016, 2015 and 2014 was 2.28%, 2.64%, and 2.60%, 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. During 2016, depreciation and amortization decreased due to changes in depreciation rates approved in the most recent final orders from the Public Utility Commission of Texas ("PUCT") and the New Mexico Public Regulation Commission ("NMPRC") and changes in the estimated life of certain intangible software assets. See Part II, Item 8, Financial Statements and Supplementary Data, Note C and Note E. Previously, the Company recorded gains and losses on the disposition of vehicles in earnings when realized. However, beginning in 2016, the Company began crediting the proceeds (salvage) on the disposition of vehicles to accumulated depreciation. 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 Nuclear 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 E. Impairment of Long-Lived Assets. Long-lived assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to estimated undiscounted future cash flows expected to be generated by the asset. If the carrying amount of an asset exceeds its estimated undiscounted future cash flows, an impairment charge is recognized for the amount by which the carrying amount of the asset exceeds the fair value of the asset. 59 EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS AFUDC and Capitalized Interest. The Company capitalizes interest ("ABFUDC") and common equity ("AEFUDC") costs to construction work in progress and capitalizes interest to nuclear fuel in process in accordance with the FERC Uniform System of Accounts as provided for in 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 2016, 2015 and 2014 were 6.43%, 7.18% and 8.15%, respectively. 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 F. 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. All temporary cash investments with an original maturity of three months or less are considered cash equivalents. Investments. The Company’s marketable securities, included in decommissioning trust funds in the balance sheet, are reported at fair value and consist of cash, equity securities and municipal, federal and corporate bonds in trust funds established for decommissioning of its interest in Palo Verde. Such marketable securities are classified as "available-for-sale" securities and, as such, unrealized gains and losses are included in accumulated other comprehensive loss as a separate component of common stock equity. However, if declines in the fair value of marketable 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 O. Derivative Accounting. Accounting for derivative instruments and hedging activities requires the recognition of derivatives as either assets or liabilities in the balance sheet with measurement of those instruments at fair value. Any changes in the fair value of these instruments are recorded in earnings or other comprehensive income. See Part II, Item 8, Financial Statements and Supplementary Data, Note O. 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 Net of Energy Expenses. The Company accrues revenues for services rendered, including unbilled electric service revenues. Energy expenses are stated at actual cost incurred. The Company’s Texas retail customers are billed under base rates and a fixed fuel factor approved by the PUCT. The Company’s New Mexico retail customers are billed under base rates and a fuel adjustment clause which is adjusted monthly, as approved by the NMPRC. The Company's FERC sales for resale customers are billed under formula base rates and fuel factors and a fuel adjustment clause which is adjusted monthly. The Company’s recovery of energy expenses is subject to periodic reconciliations of actual energy expenses incurred to actual fuel revenues collected. The difference between energy expenses incurred and fuel revenues charged to customers is reflected as over/ under-collection of fuel revenues in the balance sheets. See Part II, Item 8, Financial Statements and Supplementary Data, Note C. Revenues. Revenues related to the sale of electricity are recorded when service is provided or electricity is delivered to customers. The billing of electricity sales to retail customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. Unbilled revenues are recorded for estimated amounts of energy delivered in the period following the customers billing cycle to the end of the month. Unbilled revenues are estimated based on monthly generation volumes and by applying an average revenue/kWh to the number of estimated kWhs delivered but not billed. Accounts receivable included accrued unbilled revenues of $21.0 million and $21.7 million as of December 31, 2016 and 2015, respectively. The Company presents revenues net of sales taxes in its statements of operations. Allowance for Doubtful Accounts. The allowance for doubtful accounts represents the Company’s estimate of existing accounts receivable that will ultimately be uncollectible. The allowance is calculated by applying estimated write-off factors to various classes of outstanding receivables. The write-off factors used to estimate uncollectible accounts are based upon consideration of both historical collections experience and management’s best estimate of future collections success given the 60 EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS existing collections environment. Additions, deductions and balances for allowance for doubtful accounts for 2016, 2015 and 2014 are as follows (in thousands): Balance at beginning of year Additions: Charged to costs and expense Recovery of previous write-offs Uncollectible receivables written off Balance at end of year 2016 2015 2014 $ 2,046 $ 2,253 $ 2,261 2,427 1,395 3,712 2,156 $ 2,057 1,613 3,877 2,046 $ 2,755 1,516 4,279 2,253 $ 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. Historically, 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. During 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 final orders from the PUCT and the NMPRC in its 2015 rate cases, effective January 1, 2016. See Part II, Item 8, Financial Statements and Supplementary Data, Note C for further discussion. The effect on deferred tax assets and liabilities of a change in tax rate is recognized in income in the period that includes the enactment date. The Company recognizes tax assets and liabilities for uncertain tax positions in accordance with the recognition and measurement criteria of the FASB guidance for uncertainty in income taxes. See Part II, Item 8, Financial Statements and Supplementary Data, Note J. Earnings per Share. The Company’s restricted stock awards are participating securities and earnings per share must be calculated using the two-class method in both the basic and diluted earnings per share calculations. For the basic earnings per share calculation, net income is allocated to the weighted average number of restricted stock awards and to the weighted average number of shares outstanding. The net income allocated to the weighted average number of shares outstanding is then divided by the weighted average number of shares outstanding to derive the basic earnings per share. For the diluted earnings per share, net income is allocated to the weighted average number of restricted stock awards and to the weighted average number of shares and dilutive potential shares outstanding. The Company’s dilutive potential shares outstanding amount is calculated using the treasury stock method for the unvested performance shares. Net income allocated to the weighted average number of shares and dilutive potential shares is then divided by the weighted average number of shares and dilutive potential shares outstanding to derive the diluted earnings per share. See Part II, Item 8, Financial Statements and Supplementary Data, Note G. 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 (the "requisite service period") which typically is the vesting period. Compensation cost is not recognized for anticipated forfeitures prior to vesting of equity instruments. See Part II, Item 8, Financial Statements and Supplementary Data, Note G. Pension and Post-retirement Benefit Accounting. See Part II, Item 8, Financial Statements and Supplementary Data, Note M for a discussion of the Company’s accounting policies for its employee benefits. Reclassification. Certain amounts in the Company's financial statements for 2015 have been reclassified to conform to the 2016 presentation. The Company implemented Accounting Standards Update ("ASU") 2015-03 and ASU 2015-17 in the first quarter of 2016, retrospectively to all periods presented in the Company's financial statements. See Part II, Item 8, Financial Statements and Supplementary Data, Note I and Note O for impact of ASU 2015-03, and Note J for impact of ASU 2015-17. 61 EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS B. New Accounting Standards In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) to provide a framework that replaces the existing revenue recognition guidance, and 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. More specifically, the standard requires entities to recognize revenue through the application of a five- step model, which includes the: (i) identification of the contract; (ii) identification of the performance obligations; (iii) determination of the transaction price; (iv) allocation of the transaction price to the performance obligations; and (v) the recognition of revenue as the entity satisfies the performance obligations. Early adoption of ASU 2014-09 is permitted after December 15, 2016, however, the Company plans to adopt the new standard for reporting periods beginning after December 15, 2017. Under the new standard, companies may use either of the following transition methods: (i) a full retrospective approach reflecting the application of the standard in each prior reporting period with the option to elect certain practical expedients, or (ii) a modified retrospective approach with the cumulative effect of initially adopting ASU 2014-09 recognized at the date of adoption (which includes additional footnote disclosures). The Company has not concluded which transition method it will elect but it currently anticipates using the modified retrospective approach. The Company is currently in the process of evaluating the impact of the new standard on its various revenue and cash flow streams, including the evaluation of the impact, if any, on changes to business processes, systems and controls to support recognition and disclosure under the new guidance. Tariff sales to customers are determined to be in the scope of the new standard and represent a significant portion of the Company’s total operating revenues. The Company has not completed its final evaluation of tariff sales under the new guidance but currently does not anticipate that ASU 2014-09 will have a material impact on the Company's revenue recognition for such sales. The Company is still considering the impacts of the guidance on several industry-related accounting issues, including the accounting for contributions in aid of construction ("CIAC"), assessing the collectability criterion and the presentation of revenues associated with alternative revenue programs. The Company's initial assessment may change as we execute our implementation plan and new guidance is provided by the American Institute of Certified Public Accountants Power and Utilities Industry Task Force. In January 2016, the FASB issued ASU 2016-01, Financial Instruments-Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Liabilities to enhance the reporting model for financial instruments by addressing certain aspects of recognition, measurement, presentation, and disclosure. ASU 2016-01 generally requires entities to measure equity investments that do not result in consolidation and are not accounted for under the equity method at fair value and recognize any changes in fair value in net income. The guidance for classifying and measuring investments in debt securities and loans is not changed by this ASU, but requires entities to record changes in other comprehensive income. Financial assets and financial liabilities must be separately presented by measurement category on the balance sheet or in the accompanying notes to the financial statements. ASU 2016-01 clarifies the need for a valuation allowance on a deferred tax asset related to available-for-sale securities in combination with the entity's other deferred tax assets. The provisions of this ASU become effective for public companies for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. Upon adoption of the new standard, the Company expects to record the cumulative effects as of January 1, 2018 which will result in an adjustment to accumulated other comprehensive income (losses) and retained earnings for unrealized gains (losses) related to equity securities owned by the Company. Had the Company been required to adopt the new standard at January 1, 2016, accumulated other comprehensive income would decrease by $28.8 million and retained earnings would increase by a corresponding amount. Furthermore, the Company would report for the year ended December 31, 2016 an increase in investment income of $1.2 million, an increase in income tax expense of $0.2 million and a decrease in other comprehensive income of $1.0 million. The Company is continuing to assess the future impact of this ASU. 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 leases guidance for capital leases and operating leases. The impact of leases reported in the Company's operating results and statement of cash flows are 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 leases are recorded in regard to financial position 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. Implementation of the standard for public companies will be required for annual reporting periods beginning after December 15, 2018 and interim periods within that reporting period. Early adoption of ASU 2016-02 is permitted for all entities, however, the Company plans to adopt the new standard for reporting periods 62 EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS beginning after December 15, 2018. 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. The Company is currently in the process of evaluating the impact of the new standard, including the evaluation of the impact, if any, on changes to business processes, systems and controls to support recognition and disclosure under the new guidance, however, at this time is unable to determine the impact this standard will have on the financial statements and related disclosures. 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 will adopt the new standard effective January 1, 2017 and does not expect the effect of the adoption to be material to the Company's financial condition, results of operations or cash flows. The cumulative effect of the adoption of the new standard will be to increase net operating loss carryforward deferred tax assets and retained earnings by approximately $0.2 million on January 1, 2017. The Company also expects to continue to account for its outstanding stock awards based on the equity method and therefore does not anticipate any changes in reporting related compensation expense. In June 2016, the FASB issued ASU 2016-13, Financial Instruments - Credit Losses (Topic 326) ("ASU 2016-13"). ASU 2016-13 changes how companies measure and recognize credit impairment for many financial assets. The new current 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. For public business entities, the provisions of ASU 2016-13 are effective for fiscal years and interim periods within that reporting period beginning after December 15, 2019. Early implementation is permitted as of the fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. 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 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 new guidance addresses the following classification issues: debt prepayment or debt extinguishment costs; settlement of zero-coupon bonds; contingent consideration payments made after a business combination; proceeds from the settlement of insurance claims; proceeds from the settlement of corporate-owned life insurance policies, including bank-owned life insurance policies; distributions received from equity method investees; beneficial interests in securitization transactions; and separately identifiable cash flows and application of the predominance principle. For public business entities, the provisions of ASU 2016-15 are effective for fiscal years and interim periods within that reporting period beginning after December 15, 2017. Early adoption is permitted, including adoption in an interim period. If an entity elects early adoption of ASU 2016-15 in an interim period, adjustments should be reflected as of the beginning of the fiscal year that includes that interim period. An entity that elects early adoption must adopt all of the amendments in the same period. ASU 2016-15 will be applied using a retrospective transition method to each period presented. If it is impracticable to apply ASU 2016-15 retrospectively for some of the issues, the amendments for those issues may be applied prospectively as of the earliest date practicable. The Company is currently assessing the future impact of this ASU. In December 2016, the FASB issued ASU 2016-19, Technical Corrections and Improvements, which amends a number of Topics in the FASB ASC. This ASU is part of an ongoing FASB project to facilitate Codification updates for non-substantive technical corrections, clarifications, and improvements that are not expected to have a significant effect on accounting practice or create a significant administrative cost to most entities. Most of the amendments are effective upon issuance of ASU 2016-19 while certain amendments that require transition guidance are effective for the Company beginning January 1, 2017. The Company believes it is in compliance with those amendments that are effective immediately and that are applicable to the Company. The Company has not completed its evaluation of the new standard for amendments that require transition guidance. C. 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) transactions, 63 EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS 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 Docket No. 44941, a request for an annual increase in non-fuel base revenues (the "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 (the "Unopposed Settlement"). On August 25, 2016, the PUCT approved the Unopposed Settlement and issued its final order in Docket No. 44941 (the "PUCT Final Order"), as proposed. The PUCT Final Order provided for: (i) an annual non-fuel base rate increase, lower annual depreciation expense, a revised return on equity for AFUDC purposes, and the inclusion of substantially all new plant in service in rate base; (ii) an additional annual non-fuel base rate increase of $3.7 million related to Four Corners Generating Station ("Four Corners") costs, which will be collected through a surcharge terminating on July 12, 2017; (iii) removing the separate rate treatment for residential customers with solar systems that the Company had proposed in its August 10, 2015 filing; (iv) allowing the Company to recover $3.1 million in rate case expenses through a separate surcharge and (v) allowing the Company to recover revenues associated with the relate back of rates to consumption on and after January 12, 2016 through March 31, 2016 through a separate surcharge. 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 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 PUCT Final Order on August 25, 2016. Accordingly, it reported in the third quarter of 2016 the cumulative effect of the 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 Docket No.46831, a request for an increase in non-fuel base revenues of approximately $42.5 million. The Company invoked its statutory right to have its new rates relate back for consumption on and after July 18, 2017, which is the 155th day after the filing. The difference in rates that would have been billed will be surcharged or refunded to customers after the PUCT's final order in Docket No. 46831. The PUCT has the authority to require the Company to surcharge or refund such difference over a period not to exceed 18 months. The Company cannot predict the outcome or the timing of this rate case at this time. Energy Efficiency Cost Recovery Factor. On May 1, 2015, the Company filed its annual application to establish its energy efficiency cost recovery factor for 2016. In addition to projected energy efficiency costs for 2016 and a true-up to prior year actual costs, the Company requested approval of a $1.0 million bonus for the 2014 energy efficiency program results in accordance with PUCT rules. This case was assigned PUCT Docket No. 44677. A stipulation and settlement agreement was filed September 24, 2015 and the PUCT approved the settlement on November 5, 2015. The settlement approved by the PUCT included a performance bonus of $1.0 million. The Company recorded the performance bonus in operating revenues in the fourth quarter of 2015. On April 29, 2016, the Company filed its annual application to establish its energy efficiency cost recovery factor for 2017. In addition to projected energy efficiency costs for 2017 and true-up to prior year actual costs, the Company requested approval of a $0.7 million bonus for the 2015 energy efficiency program results in accordance with PUCT rules. This case was assigned PUCT Docket No. 45885. Parties in the proceeding, including PUCT staff and the City of El Paso, filed a settlement in the case that approved the Company's proposal with a reduction to the 2015 program bonus of $0.2 million. The PUCT approved the settlement on October 28, 2016. The settlement approved by the PUCT included a performance bonus of $0.5 million which was recorded in operating revenues in the third quarter of 2016. 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 (the "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 64 EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS surcharge fuel under-recoveries in any month the balance exceeds a threshold material amount and it expects fuel cost recovery to continue to be materially under-recovered. Fuel over and under-recoveries are considered material when they exceed 4% of the previous twelve months' fuel costs. All such fuel revenue and expense activities are subject to periodic final review by the PUCT in fuel reconciliation proceedings. On April 15, 2015, the Company filed a request, which was assigned PUCT Docket No. 44633, to reduce its fixed fuel factor by approximately 24% to reflect reduced fuel expenses primarily related to a reduction in the price of natural gas used to generate power. The over-recovered balance was below the PUCT's materiality threshold. The reduction in the fixed fuel factor was effective on an interim basis May 1, 2015 and approved by the PUCT on May 20, 2015. On November 30, 2016, the Company filed a request, 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. As of December 31, 2016, the Company had under-recovered fuel costs in the amount of $11.1 million for the Texas jurisdiction. 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. A procedural schedule has been adopted with hearings in April 2017. As of December 31, 2016, Texas jurisdictional fuel and purchased power costs subject to a future Texas fuel reconciliation are approximately $114.4 million. The Company cannot predict the outcome or the timing of this matter. Montana Power Station Approvals. The Company received Certificate of Convenience and Necessity ("CCN") approval from the PUCT to construct four natural gas fired generating units at Montana Power Station ("MPS") in El Paso County, Texas. The Company also obtained air permits from the Texas Commission on Environmental Quality (the "TCEQ") and the U.S. Environmental Protection Agency (the "EPA"). MPS Units 1 and 2 and associated transmission lines and common facilities were completed and placed into service in March 2015. MPS Units 3 and 4 were completed and placed into service on May 3, 2016 and September 15, 2016, respectively. 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 3 MW solar photovoltaic system located at MPS. Participation will be on a voluntary basis, and customers will 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. The Company expects completion of the solar facility and commencement of the program in the second quarter of 2017. Four Corners. On February 17, 2015, the Company and Arizona Public Service Company ("APS") entered into an asset purchase agreement (the "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 E for further details 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 has been 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 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, and the parties are engaged in settlement discussions. At December 31, 2016, the regulatory asset associated with the Four Corners mine reclamation costs for the Company's Texas jurisdiction was approximately $7.3 million. The Company currently continues to recover its mine reclamation costs in Texas under previous orders and decisions of the PUCT. If any future determinations made by the Company's regulators result in changes to how existing regulatory assets or previously incurred costs for Four Corners are recovered in rates, any such changes would be recognized only when it becomes probable future cash flows will change as a result of such regulatory actions. Other Required Approvals. The Company has obtained other required approvals for tariffs and approvals required by the Public Utility Regulatory Act (the "PURA") and the PUCT. 65 EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS 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 (the "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 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. Fuel and Purchased Power Costs. On January 8, 2014, the NMPRC approved the continuation of the Fuel and Purchased Power Cost Adjustment Clause (the "FPPCAC") without modification in NMPRC Case No. 13-00380-UT. Historically, fuel and purchased power costs were recovered through base rates and a 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 final order in Case No. 15-00127-UT, fuel and purchased power costs are no longer recovered through base rates 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. The Company recovers costs related to Palo Verde Unit 3 capacity and energy in New Mexico through the FPPCAC as purchased power using a proxy market price approved in Case No. 13-00380-UT. 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 Case No. 15-00127- UT. New Mexico jurisdictional costs subject to prudence review are costs from January 1, 2015 through December 31, 2016 that total approximately $114.6 million. At December 31, 2016, the Company had a net fuel over-recovery balance of $0.2 million in New Mexico. Montana Power Station Approvals. The Company received CCNs from the NMPRC to construct four units at MPS and the associated transmission lines. The Company also obtained all necessary air permits from the TCEQ and the EPA. A final order in NMPRC Case No. 13-00297-UT approving the CCN for MPS Units 3 and 4 was issued on June 11, 2014. MPS Units 1 and 2 and associated transmission lines and common facilities were completed and placed into service in March 2015. MPS Units 3 and 4 were completed and placed into service on May 3, 2016 and September 15, 2016, respectively. Four Corners. On June 15, 2016, in NMPRC Case No. 15-00109-UT, the NMPRC issued its final order approving the Company's sale and abandonment of its ownership interest in Four Corners to APS pursuant to a February 17, 2015 Purchase and Sale Agreement between the Company and APS. See Part II, Item 8, Financial Statements and Supplementary Data, Note E for further details on the sale of Four Corners. 5 MW Holloman Air Force Base ("HAFB") Facility CCN. On October 7, 2015, in NMPRC Case No. 15-00185-UT, the NMPRC issued a final order approving a CCN for a 5 MW solar power generation facility located on HAFB in the Company's service territory in New Mexico. The Company and HAFB negotiated a special retail contract, which includes power sales agreement for the facility, to replace the existing load retention agreement which was approved by final order issued October 5, 2016 in NMPRC Case No. 16-00224-UT. Construction of the solar generation facility is expected to be completed in the second quarter of 2017. Issuance of Long-Term Debt and Guarantee of Debt. On October 7, 2015 the Company received approval in NMPRC Case No. 15-00280-UT to issue up to $310.0 million of new long-term debt and to guarantee the issuance of up to $65.0 million of new debt by Rio Grande Resources Trust ("RGRT") to finance future purchases of nuclear fuel and to refinance existing nuclear fuel debt obligations. This approval supersedes prior approvals. Under this authorization, on March 24, 2016, the Company issued $150.0 million aggregate principal amount of 5.00% Senior Notes due December 1, 2044. The net proceeds from the issuance of these senior notes, after deducting the underwriters' commission, were $158.1 million. These proceeds include accrued interest of $2.4 million and a $7.1 million premium before expenses. These senior notes constitute an additional issuance of the Company's 5.00% Senior Notes due 2044, of which $150.0 million was previously issued on December 1, 2014, for a total principal amount outstanding of $300.0 million. Other Required Approvals. The Company has obtained other required approvals for other tariffs, securities transactions, recovery of energy efficiency costs through a base rate rider and other approvals as required by the NMPRC. 66 EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS Federal Regulatory Matters Four Corners. On June 26, 2015, APS filed an application requesting authorization from FERC to purchase 100% of the Company’s ownership interest in Units 4 and 5 of Four Corners and the associated transmission interconnection facilities and rights. On December 22, 2015, FERC issued an order approving the proposed transaction. 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 E for further details on the sale of Four Corners. Revolving Credit Facility; Issuance of Long-Term Debt and Guarantee of Debt. On October 19, 2015, the FERC issued an order in Docket No. ES15-66-000 approving the Company’s filing to issue short-term debt under the revolving credit facility ("RCF") up to $400.0 million outstanding at any time, to issue up to $310.0 million in long-term debt, and to guarantee the issuance of up to $65.0 million of new long-term debt by RGRT to finance future nuclear fuel purchases. The authorization is effective from November 15, 2015 through November 15, 2017. This approval supersedes prior approvals. Under this authorization, on March 24, 2016, the Company issued $150.0 million aggregate principal amount of 5.00% Senior Notes due December 1, 2044. Additionally under this authorization, 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 $50.0 million to $350.0 million. The Company still has the option to extend the facility by one additional year to January 2021 and to increase the RCF by up to $50.0 million (up to a total of $400.0 million) upon the satisfaction of certain conditions, more fully set forth in the agreement, including obtaining commitments from lenders or third party financial institutions. Additionally, the Company agreed to reduce the letters of credit commitment to $50.0 million from a total commitment, under the RCF, of $350.0 million. Other Required Approvals. The Company has obtained required approvals for rates and tariffs, securities transactions and other approvals as required by the FERC. United States Department of Energy ("DOE"). The DOE regulates the Company's exports of power to the Comisión Federal de Electricidad in Mexico pursuant to a license and two presidential permits issued by the DOE. 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 E for discussion of spent fuel storage and disposal costs. Sales for Resale The Company provides firm capacity and associated energy to the Rio Grande Electric Cooperative ("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 Open Access Transmission Tariff ("OATT"). The contract includes a formula- based rate that is updated annually to recover non-fuel generation costs and a fuel adjustment clause designed to recover all eligible fuel and purchased power costs allocable to the RGEC. 67 EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS D. Regulatory Assets and Liabilities The Company's operations are regulated by the PUCT, the NMPRC and the FERC. Regulatory assets represent probable future recovery of previously incurred costs, which will be collected from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are to be credited to customers through the ratemaking process. Regulatory assets and liabilities reflected in the Company's balance sheet are presented below (in thousands): Amortization Period Ends December 31, 2016 December 31, 2015 Regulatory assets Regulatory tax assets (a) Loss on reacquired debt (c) Final coal reclamation (d) Nuclear fuel postload daily financing charge Unrecovered issuance costs due to reissuance of PCBs (c) Texas energy efficiency Texas 2015 rate case costs Texas 2017 rate case costs Texas relate back surcharge New Mexico renewable energy credits and related costs (i) New Mexico 2010 FPPCAC audit New Mexico Palo Verde deferred depreciation New Mexico 2015 rate case costs New Mexico 2017 rate case costs Total regulatory assets Regulatory liabilities Regulatory tax liabilities (a) Accumulated deferred investment tax credit (j) Texas energy efficiency New Mexico energy efficiency Texas military base discount and recovery factor New Mexico gain on sale of assets (l) Total regulatory liabilities (b) May 2035 (e) (e) August 2042 (f) September 2018 (g) (h) June 2022 June 2019 (b) June 2019 (g) (b) (b) (f) (f) (k) June 2019 $ $ $ $ 66,670 15,780 9,581 3,831 794 — 2,670 246 6,455 6,937 398 4,415 1,074 10 118,861 10,648 3,328 1,288 2,159 184 828 18,435 $ $ $ $ 69,359 16,632 9,520 4,195 827 25 1,882 — — 6,397 434 4,568 1,288 — 115,127 17,266 4,011 — 2,238 788 — 24,303 ______________________________ (a) We do not earn a return on these items since the related accumulated deferred income tax assets and liabilities offset. (b) The amortization periods for these assets and liabilities are based upon the life of the associated assets or liabilities. (c) This item is recovered as a component of the weighted cost of debt and amortized over the life of the related debt issuance. (d) This item relates to coal reclamation costs associated with Four Corners. See Part II, Item 8, Financial Statements and Supplementary Data, Note C. (e) This item is recovered through fuel recovery mechanisms established by tariffs. (f) This item is recovered or credited through a recovery factor that is set annually. (g) Amortization period is anticipated to be established in next general rate case. (h) This item relates to the recovery of revenues through a separate surcharge beginning October 1, 2016 and ending September (i) 30, 2017. See Part II, Item 8, Financial Statements and Supplementary Data, Note C. This item relates to renewable energy credits and procurement plan costs, components approved for recovery in the New Mexico 2015 rate case. This item is excluded from rate base. (j) (k) This item represents the net asset/net liability related to the military discount which is recovered from non-military customers (l) through a recovery factor that is set annually. This item relates to the gains on the sales of assets the Company shares with its New Mexico customers over a three year period. 68 EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS E. Utility Plant, Palo Verde and Other Jointly-Owned Utility Plant The table below presents the balance of each major class of depreciable assets at December 31, 2016 (in thousands): Nuclear production Steam and other Total production Transmission Distribution General Intangible Total $ Gross Plant 948,382 926,419 1,874,801 498,660 1,127,897 205,866 84,342 $ 3,791,566 $ Accumulated Depreciation Net Plant 628,382 739,880 1,368,262 239,172 762,296 148,626 28,878 $ (1,244,332) $ 2,547,234 (320,000) $ (186,539) (506,539) (259,488) (365,601) (57,240) (55,464) During 2016, depreciation decreased due to changes in rates approved in the PUCT Final Order and the NMPRC Final Order. The change, effective in January 2016 for Texas and July 2016 for New Mexico, reduced depreciation expense in 2016 by $10.9 million. 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). Effective July 2015, the Company changed the estimated useful life of certain large intangible software systems which decreased depreciation during 2015 by $1.8 million. 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): 2014 2015 2016 2017 (estimated) 2018 (estimated) 2019 (estimated) 2020 (estimated) 2021 (estimated) $ 8,051 6,482 5,302 5,148 4,631 4,242 3,808 3,227 The Company owns a 15.8% interest in each of the three nuclear generating units and common facilities at Palo Verde, in Wintersburg, Arizona. The Palo Verde Participants include the Company and six other utilities: APS, Southern California Edison Company ("SCE"), PNM, Southern California Public Power Authority, Salt River Project Agricultural Improvement and Power District ("SRP") and the Los Angeles Department of Water and Power. A summary of the Company’s investment in jointly-owned utility plant, excluding fuel inventories, at December 31, 2016 and 2015 is as follows (in thousands): Electric plant in service Accumulated depreciation Construction work in progress Total December 31, 2016 December 31, 2015 Palo Verde Other (a) Palo Verde Other (a) $ $ 948,382 (320,000) 50,598 678,980 $ $ 67,621 (44,377) 1,895 25,139 $ $ 917,483 (304,060) 48,938 662,361 $ $ 229,627 (181,886) 9,528 57,269 _______________ (a) 2015 other jointly-owned utility plant includes a 7% interest in Units 4 and 5 at Four Corners and certain other transmission facilities which the Company sold on July 6, 2016. 69 EL PASO ELECTRIC COMPANY 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 (the "ANPP Participation Agreement"). APS serves as operating agent for Palo Verde, and under the ANPP Participation Agreement, the Company has limited ability to influence operations and costs at Palo Verde. Pursuant to the ANPP Participation Agreement, the Palo Verde Participants share costs and generating entitlements in the same proportion as their percentage interests in the generating units, and each participant is required to fund its share of fuel, other operations, maintenance and capital costs. The Company’s share of direct expenses in Palo Verde and other jointly-owned utility plants is reflected in fuel expense, other operations expense, maintenance expense, miscellaneous other deductions, and taxes other than income taxes in the Company’s 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 Nuclear Regulatory Commission ("NRC") regulates the operation of all commercial nuclear power reactors in the United States, including Palo Verde. The NRC periodically conducts inspections of nuclear facilities and monitors performance indicators to enable the agency to arrive at objective conclusions about a licensee’s safety performance. 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 external trusts with an independent trustee, which enables the Company to record a current deduction for federal income tax purposes for most of the amounts funded. At December 31, 2016, the Company’s decommissioning trust fund had a balance of $255.7 million, which is above its minimum funding level. The Company monitors the status of its decommissioning funds and adjusts its deposits, if necessary. Decommissioning costs are estimated every three years based upon engineering cost studies performed by outside engineers retained by APS. In December 2013, the Palo Verde Participants approved the 2013 Palo Verde decommissioning study (the "2013 Study"). The 2013 Study estimated that the Company must fund approximately $380.7 million (stated in 2013 dollars) to cover its share of decommissioning costs which was an increase in decommissioning costs of $23.3 million (stated in 2013 dollars) from the 2010 Palo Verde decommissioning study. However, because the cash flows from the 2013 Study were less than the inflated amounts from the 2010 Study, the effect of this change lowered the ARO by $1.9 million which lowered annual expenses starting in January 2014. Although the 2013 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. A 2016 Palo Verde decommissioning study (the "2016 Study") is underway and is expected to be finalized in the second quarter of 2017 at which time the Company will record its effects. If the expected cash flows as identified in the 2016 Study exceed the expected cash flows identified in the 2013 Study (stated in 2016 dollars), the ARO will increase with a corresponding increase in the ARO asset. Under such circumstances, increases in Palo Verde accretion expense and depreciation expense will occur. 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 Nuclear Fuel and Waste Disposal. Pursuant to the Nuclear Waste Policy Act of 1982, as amended in 1987 (the "NWPA"), 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 (the "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 70 EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS Verde’s spent nuclear fuel for the period beginning January 1, 2007 through June 30, 2011. On August 18, 2014, APS and the DOE entered into a settlement agreement stipulating to a dismissal of the lawsuit and payment of $57.4 million by the DOE to the Palo Verde Participants for certain specified costs incurred by Palo Verde during the period January 1, 2007 through June 30, 2011. On October 8, 2014, the Company received approximately $9.1 million, representing its share of the award, of which $7.9 million was refunded to customers through the applicable fuel adjustment clauses. On October 31, 2014, APS, acting on behalf of itself and the Palo Verde Participants, submitted to the government an additional request for reimbursement of spent nuclear fuel storage costs for the period July 1, 2011 through June 30, 2014. The accepted claim amount was $42.0 million. On June 1, 2015, the Company received approximately $6.6 million, representing its share of the award, of which $5.8 million was credited to customers through the applicable fuel adjustment clauses in March 2015. After June 2015, APS will file annual claims for the period July 1 of the then-previous year to June 30 of the then-current year. On November 2, 2015, APS filed a $12.0 million claim for the period July 1, 2014 through June 30, 2015. In February 2016, the DOE notified APS of the approval of the claim. The Company's share of this claim is approximately $1.9 million, of which $1.6 million was credited to customers through the applicable fuel adjustment clauses in March 2016. On October 31, 2016 APS filed an $11.3 million claim for the period July 1, 2015 through June 30, 2016. The Company's share of this claim is approximately $1.8 million. On February 1, 2017, the DOE notified APS of the approval of the claim. Any reimbursement is anticipated to be received in the second quarter of 2017, and the majority of the award received by the Company will be credited to customers through 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, and the proceeding has not been conclusively decided by the NRC or the courts. 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 United States 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 $13.4 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 $127.3 million, subject to an annual limit of $19.0 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 $60.4 million, with an annual payment limitation of approximately $9.0 million. The Palo Verde Participants maintain $2.75 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 $2.25 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 $12.9 million for the current policy period. 71 EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS Four Corners On February 17, 2015, the Company and APS entered into the Purchase and Sale Agreement providing for the sale of the Company’s interests in Four Corners to APS. Four Corners continued to provide energy to serve the Company's native load up to the closing date of the sale on July 6, 2016. Also on July 6, 2016, prior to the closing of the transaction, the Company and APS entered into an amendment to the Purchase and Sale Agreement pursuant to which APS assigned its right, title and interest in the Purchase and Sale Agreement to its affiliate 4C Acquisition, LLC ("APS's affiliate"), and Pinnacle West Capital Corporation, the parent company of APS and APS's affiliate ("Pinnacle West"), guaranteed APS's affiliate's obligations under the Purchase and Sale Agreement. The sales price was $32.0 million, which was based on the net book value as defined in the Purchase and Sale Agreement. The sales price was adjusted downward by $7.0 million and $19.5 million, respectively, to reflect the assumption by APS's affiliate of the Company's obligation to pay for future plant decommissioning and mine reclamation expenses. The sales price was also adjusted downward by approximately $1.3 million for estimated closing adjustments and other assets and liabilities assumed by APS's affiliate. At the closing, the Company received approximately $4.2 million in cash, subject to post-closing adjustments. No significant gain or loss was recorded after the closing date. 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 C for a discussion of regulatory filings associated with Four Corners. F. Accounting for Asset Retirement Obligation The Company complies with the FASB guidance for ARO. 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 2013 Palo Verde decommissioning study. See Part II, Item 8, Financial Statements and Supplementary Data, Note E. The ARO liability is calculated by adjusting the estimated decommissioning costs for spent fuel storage and a profit margin and market-risk premium factor. The resulting costs are escalated over the remaining life of the plant and finally discounted using a credit-risk adjusted discount rate. As Palo Verde approaches the end of its estimated useful life, the difference between the ARO liability and future current cost estimates will narrow over time due to the accretion of the ARO liability. Because the DOE is obligated to assume responsibility for the permanent disposal of spent fuel, spent fuel costs have not been included in the ARO calculation. The Company 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, 2016 is $255.7 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. In December 2013, the Company implemented the 2013 Palo Verde decommissioning study, and as a result, revised its ARO related to Palo Verde to decrease its estimated cash flows from the 2010 Study to the 2013 Study (see Part II, Item 8, Financial Statements and Supplementary Data, Note E). The assumptions used to calculate the Palo Verde ARO liability are as follows: Original ARO liability Incremental ARO liability Credit-Risk Adjusted Discount Rate 9.50% 6.20% Escalation Rate 3.60% 3.60% 72 EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS An analysis of the activity of the Company’s total ARO liability from January 1, 2014 through December 31, 2016, including the effects of each year’s estimate revisions, is presented below. In 2016, the settled liabilities reflect the sale of the Company's interest in Four Corners including the related ARO. In 2014, the estimate revision includes an adjustment to Four Corners due to the early recognition of the obligation resulting from the Purchase and Sale Agreement with APS. ARO liability at beginning of year Liabilities incurred Liabilities settled Revisions to estimate Accretion expense ARO liability at end of year 2016 81,621 — (6,993) — 7,172 81,800 $ $ 2015 74,577 189 — — 6,855 81,621 $ $ 2014 65,214 — — 3,561 5,802 74,577 $ $ The Company has transmission and distribution lines which are operated under various property easement agreements. If the easements were to be released, the Company may have a legal obligation to remove the lines; however, the Company has assessed the likelihood of this occurring as remote. The majority of these easements include renewal options which the Company routinely exercises. The amount of cost of removal collected in rates for non-legal liabilities has not been material. G. Common Stock Overview The Company’s common stock has a stated value of $1 per share, with no cumulative voting rights or preemptive rights. Holders of the common stock have the right to elect the Company’s directors and to vote on other matters. Long-Term Incentive Plan On May 29, 2014, the Company’s shareholders approved an amended and restated stock-based long-term incentive plan (the "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, 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. 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 are fully vested and are expensed at fair value on the date of grant. Previously directors could elect to receive retainers and meeting fees in cash, restricted stock, or a combination of cash and stock. On May 29, 2014, the Board of Directors voted to revise the terms of the restricted stock awards granted to directors in lieu of cash for retainers and meeting fees. Stock elections by directors in lieu of cash for retainer and meeting fees are now fully vested and are expensed at fair value on the date of grant. The modification to 13,863 outstanding restricted stock awards granted to directors resulted in forfeiture of those awards and the granting of new awards which were fully vested and expensed at $37.81 per share, the fair value on the date of grant. Effective fiscal year ended December 31, 2015, other stock-based awards are not included in the tables below. 73 EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS The expense, deferred tax benefit, and current tax expense recognized related to restricted stock and other stock-based awards in 2016, 2015 and 2014 is presented below (in thousands): Expense (a) Deferred tax benefit $ 2,594 $ 908 2,755 $ 964 2016 2015 2014 Current tax benefit recognized _____________________ (a) Any capitalized costs related to these expenses is less than $0.3 million for all years. 183 43 3,471 1,215 39 The aggregate intrinsic value and fair value at grant date of restricted stock and other stock-based awards which vested in 2016, 2015 and 2014 is presented below (in thousands): 2016 2015 2014 Aggregated intrinsic value Fair value at grant date $ $ 2,515 1,993 $ 3,451 3,327 3,441 3,330 The unvested restricted stock transactions for 2016 are presented below: Weighted Average Grant Date Fair Value Total Shares Unrecognized Compensation Expense (a) (In thousands) Aggregate Intrinsic Value (In thousands) Restricted shares outstanding at December 31, 2015 91,210 $ Stock awards Vested Forfeitures Restricted shares outstanding at December 31, 2016 74,181 (55,503) (495) 109,393 36.61 40.95 35.91 36.88 39.90 $ 1,767 $ 5,087 _______________________ (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. The weighted average fair value per share at grant date for restricted stock and other stock-base awards granted during 2016, 2015 and 2014 were: Weighted average fair value per share $ 40.95 $ 37.17 $ 36.95 2016 2015 2014 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. 74 EL PASO ELECTRIC COMPANY 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: Date Vested Payout Ratio Performance Shares Awarded Compensation Costs Expensed (In thousands) Period Compensation Costs Expensed Aggregated Intrinsic Value (In thousands) 2014-2016 $ 512 January 25, 2017 32% 11,314 $ January 27, 2016 February 20, 2015 February 18, 2014 0% 0% 0% 0 0 0 932 851 2013-2015 1,502 2012-2014 954 2011-2013 — — — In 2017, 2018 and 2019, subject to meeting certain performance criteria, additional performance shares could be awarded. 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. Excluding the 2014 award, the maximum number of shares that can be issued under the plan are 206,898 shares. The fair value at the date of each separate grant of performance shares was based upon a Monte Carlo simulation. The Monte Carlo simulation reflected the structure of the performance plan which calculates the share payout on performance of the Company relative to a defined peer group over a three-year performance period based upon total return to shareholders. The fair value was determined as the average payout of one million simulation paths discounted to the grant date using a risk-free interest rate based upon the constant maturity treasury rate yield curve at the grant date. The expected volatility of total return to shareholders is calculated in accordance with the plan’s term structure and includes the volatilities of all members of the defined peer group. The outstanding performance share awards at the 100% performance level is summarized below: Number Outstanding Weighted Average Grant Date Fair Value Unrecognized Compensation Expense (b) Aggregate Intrinsic Value (In thousands) (In thousands) Performance shares outstanding at December 31, 2015 (a) Performance share awards Performance shares expired 130,136 $ 60,835 (24,527) 32.72 38.11 34.69 Performance shares outstanding at December 31, 2016 (a) _______________________ (a) On December 15, 2015, the Company issued a stock based retention grant to the Chief Executive Officer (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 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. 166,444 7,740 2,189 34.40 $ $ (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 CEO retention grant. 75 EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS A summary of information related to performance shares for 2016, 2015 and 2014 is presented below: Weighted average per share grant date fair value per share of performance shares awarded Compensation expense (in thousands) (a) (b) Deferred tax benefit related to compensation expense (in thousands) (b) $ 38.11 $ 1,655 579 35.72 1,042 365 $ 26.36 1,181 413 2016 2015 2014 _____________________ (a) Includes adjustments for estimated forfeitures. (b) Includes CEO retention grant. Repurchase Program No shares of the Company's common stock were repurchased during the twelve months ended December 31, 2016. Detail regarding the Company's stock repurchase program are presented below: Shares repurchased (b) Cost, including commission (in thousands) Since 1999 (a) Authorized Shares 25,406,184 $ 423,647 Total remaining shares available for repurchase at December 31, 2016 393,816 ______________________ (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 outside of the Company's repurchase programs. 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 awarded 188,005 shares out of treasury stock during 2016. 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 may be retired. Dividend Policy On December 30, 2016, the Company paid $12.6 million in quarterly cash dividends to shareholders. The Company paid a total of $49.6 million, $47.1 million and $44.6 million in cash dividends during the twelve months ended December 31, 2016, 2015 and 2014, respectively. On January 26, 2017, the Board of Directors declared a quarterly cash dividend of $0.31 per share payable on March 31, 2017 to shareholders of record as of the close of business on March 17, 2017. 76 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: Weighted average number of common shares outstanding: Basic number of common shares outstanding Dilutive effect of unvested performance awards Diluted number of common shares outstanding Basic net income per common share: Net income Income allocated to participating restricted stock Net income available to common shareholders Diluted net income per common share: Net income Income reallocated to participating restricted stock Net income available to common shareholders Basic net income per common share: Distributed earnings Undistributed earnings Basic net income per common share Diluted net income per common share: Distributed earnings Undistributed earnings Diluted net income per common share Years Ended December 31, 2015 2014 2016 40,350,688 57,345 40,408,033 40,274,986 33,576 40,308,562 40,190,991 20,726 40,211,717 $ $ $ $ $ $ $ $ 96,768 (321) 96,447 96,768 (321) 96,447 1.225 1.165 2.390 1.225 1.165 2.390 $ $ $ $ $ $ $ $ 81,918 (243) 81,675 81,918 (243) 81,675 1.165 0.865 2.030 1.165 0.865 2.030 $ $ $ $ $ $ $ $ 91,428 (301) 91,127 91,428 (301) 91,127 1.105 1.165 2.270 1.105 1.165 2.270 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: Restricted stock awards Performance shares (a) Year Ended December 31, 2015 56,375 2016 53,703 47,246 66,804 2014 60,455 96,208 _____________________ (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. 77 EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS H. Accumulated Other Comprehensive Income (Loss) Changes in Accumulated Other Comprehensive Income (Loss) (net of tax) by component are presented below (in thousands): Unrecognized Pension and Post- retirement Benefit Costs Net Unrealized Gains (Losses) on Marketable Securities Net Losses on Cash Flow Hedges Accumulated Other Comprehensive Income (Loss) Balance at December 31, 2013 $ (21,330) $ 36,240 $ (12,298) $ 2,612 Other comprehensive income (loss) before reclassifications Amounts reclassified from accumulated other comprehensive income (loss) Balance at December 31, 2014 Other comprehensive income (loss) before reclassifications Amounts reclassified from accumulated other comprehensive income (loss) Balance at December 31, 2015 Other comprehensive income before reclassifications Amounts reclassified from accumulated other comprehensive income (loss) Balance at December 31, 2016 $ (12,628) 8,694 (926) (34,884) 3,777 1,238 (29,869) 7,363 (5,977) 38,957 (2,255) (8,937) 27,765 6,904 — 224 (12,074) — 264 (11,810) (3,934) (6,679) (8,001) 1,522 (7,435) (13,914) — 14,267 (1,422) (23,928) $ (6,206) 28,463 $ 159 (11,651) $ (7,469) (7,116) 78 EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS Amounts reclassified from Accumulated Other Comprehensive Income (Loss) for the twelve months ended December 31, 2016, 2015 and 2014 are as follows (in thousands): Details about Accumulated Other Comprehensive Income (Loss) Components 2016 2015 2014 Affected Line Item in the Statements of Operations Amortization of pension and post- retirement benefit costs: Prior service benefit Net loss Income tax effect Marketable securities: $ 7,407 $ (4,965) 2,442 (1,020) 1,422 $ 6,574 (8,622) (2,048) 810 (1,238) 7,659 (a) (6,182) (a) 1,477 (a) (551) Income tax expense 926 Net income Net realized gain on sale of securities 7,640 11,114 Income tax effect Loss on cash flow hedge: Amortization of loss Income tax effect 7,640 (1,434) 6,206 11,114 (2,177) 8,937 (498) (498) 339 (159) (467) (467) 203 (264) 7,350 Investment and interest income, net Income before income taxes 7,350 (1,373) Income tax expense 5,977 Net income (438) Interest on long- term debt and revolving credit facility Income before income taxes (438) 214 Income tax expense (224) Net income Total reclassifications $ 7,469 $ 7,435 $ 6,679 (a) These items are included in the computation of net periodic benefit cost. See Part II, Item 8, Financial Statements and Supplementary Data, Note M for additional information. 79 EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS I. Long-Term Debt and Financing Obligations Outstanding long-term debt and financing obligations are as follows: Long-Term Debt: Pollution Control Bonds (2): 7.25% 2009 Series A refunding bonds, due 2040 (7.46% effective interest rate) 4.50% 2012 Series A refunding bonds, due 2042 (4.63% effective interest rate) 7.25% 2009 Series B refunding bonds, due 2040 (7.49% effective interest rate) 1.875% 2012 Series A refunding bonds, due 2032 (2.35% effective interest rate) $ Total Pollution Control Bonds Senior Notes (3): 6.00% Senior Notes, net of discount, due 2035 (7.12% effective interest rate) 7.50% Senior Notes, net of discount, due 2038 (7.67% effective interest rate) 3.30% Senior Notes, net of discount, due 2022 (3.43% effective interest rate) 5.00% Senior Notes, net of discount, due 2044 (4.93% effective interest rate) Total Senior Notes RGRT Senior Notes (4): 4.47% Senior Notes, Series B, due 2017 (4.62% effective interest rate) 5.04% Senior Notes, Series C, due 2020 (5.16% effective interest rate) Total RGRT Senior Notes Total long-term debt Financing Obligations: Revolving Credit Facility ($81,574 due in 2017) (5) Total long-term debt and financing obligations Current Portion (amount due within one year): Current maturities of long term debt Short-term borrowings under the revolving credit facility December 31, 2016 2015 (1) (In thousands) $ 62,619 58,471 36,492 33,193 190,775 393,861 147,331 148,939 302,955 993,086 62,582 58,441 36,465 33,011 190,499 393,693 147,282 148,783 147,717 837,475 49,950 44,845 94,795 1,278,656 49,883 44,803 94,686 1,122,660 81,574 1,360,230 141,738 1,264,398 (83,143) (81,574) $ 1,195,513 — (141,738) $ 1,122,660 _____________________ (1) The Company implemented ASU 2015-03, Interest - Imputation of Interest, which requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability. ASU 2015-03 is effective for financial statements issued for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. The impact of ASU 2015-03 on the Company's Balance Sheet was to reclassify $11.6 million of other deferred charges to long-term debt, net of current portion at December 31, 2015. (2) Pollution Control Bonds ("PCBs") The Company has four series of tax exempt unsecured PCBs in aggregate principal amount of $193.1 million. The 1.875% 2012 Series A (El Paso Electric Company Four Corners Project) Pollution Control Refunding Revenue Bonds with an aggregate principal amount of $33.3 million are subject to mandatory tender for purchase in September 2017 at which time the Company will either repay or remarket these bonds. (3) Senior Notes The Senior Notes are unsecured obligations of the Company. They were issued pursuant to bond covenants that provide limitations on the Company’s ability to enter into certain transactions. The 6.00% Senior Notes have an aggregate principal amount of $400.0 million and were issued in May 2005. The proceeds, net of a $2.3 million discount, were used to fund the retirement of the Company's first mortgage bonds. The Company amortizes the loss associated with a cash flow hedge 80 EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS 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 O. This amortization is included in the effective interest rate of the 6.00% Senior Notes. The 7.50% Senior Notes have an aggregate principal amount of $150.0 million and were issued in June 2008. The proceeds, net of a $1.3 million discount, were used to repay short-term borrowings of $44.0 million, fund capital expenditures and for other general corporate purposes. The 3.30% Senior Notes have an aggregate principal amount of $150.0 million were issued in December 2012. The proceeds, net of a $0.3 million discount, were used to 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. (4) 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 sold to the purchasers $110 million aggregate principal amount of Senior Notes (the "Notes"). In August 2015, $15.0 million of these Notes matured and were paid with borrowings from the RCF. In August 2017, $50.0 million of these Senior Notes will mature. The Company will either repay or refinance this $50.0 million of Notes upon maturity. The Company guarantees the payment of principal and interest on the Notes. In the Company’s financial statements, the assets and liabilities of RGRT are reported as assets and liabilities of the Company. RGRT pays interest on the Notes on February 15, and August 15 of each year until maturity. RGRT may redeem the Notes, in whole or in part, at any time at a redemption price equal to 100% of the principal amount to be redeemed together with the interest on such principal amount accrued to the date of redemption, plus a make-whole amount based on the prevailing market interest rates. The agreement requires compliance with certain covenants, including a total debt to capitalization ratio. The Company was in compliance with these requirements throughout 2016. The sale of the Notes was made by RGRT in reliance on a private placement exemption from registration under the Securities Act of 1933, as amended. The proceeds of $109.4 million, net of issuance costs, from the sale of the Notes was used by RGRT to repay amounts borrowed under the RCF and will enable future nuclear fuel financing requirements of RGRT to be met with a combination of the Notes and amounts borrowed from the RCF. (5) 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. The Company still has the option to extend the facility by one additional year to January 2021 and to increase the RCF by up to $50 million (up to a total of $400 million) upon the satisfaction of certain conditions, more fully set forth in the agreement, including obtaining commitments from lenders or third party financial institutions. The RCF provides that amounts borrowed by the Company may be used for, among other things, working capital and general corporate purposes. Any amounts borrowed by RGRT may be used, among other things, to finance the acquisition and processing of nuclear fuel. Amounts borrowed by RGRT are guaranteed by the Company and the balance borrowed under the RCF is recorded as short-term borrowings on the balance sheet. The RCF is unsecured. The RCF requires compliance 81 EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS with certain covenants, including a total debt to capitalization ratio. The Company was in compliance with these requirements throughout 2016. In August 2015, $15.0 million aggregate principal amount of Series A 3.67% Senior Notes of RGRT matured and were paid utilizing borrowings under the RCF. As of December 31, 2016, the total amount borrowed by RGRT was $37.6 million for nuclear fuel under the RCF. As of December 31, 2016, $44.0 million of borrowings were outstanding under this facility for working capital and general corporate purposes. The weighted average interest rate on the RCF was 2.0% as of December 31, 2016. As of December 31, 2016, the principal amount of scheduled maturities for the next five years of long-term debt are as follows (in thousands): 2017 2018 2019 2020 2021 $ 83,300 — — 45,000 — The $37.6 million of borrowings outstanding on the RCF for nuclear fuel financing purposes is anticipated to be paid in 2017. J. Income Taxes The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and liabilities at December 31, 2016 and 2015 are presented below (in thousands): Deferred tax assets: Benefit of tax loss carryforwards Alternative minimum tax credit carryforward Pensions and benefits Asset retirement obligation Deferred fuel Other Total gross deferred tax assets Deferred tax liabilities: Plant, principally due to depreciation and basis differences Decommissioning Deferred fuel Other Total gross deferred tax liabilities Net accumulated deferred income taxes December 31, 2016 2015 $ 60,749 16,620 57,756 26,929 — (200) 161,854 35,153 16,620 61,673 28,042 1,488 15,421 158,397 (668,303) (43,463) (3,962) (1,192) (716,920) (555,066) $ (608,738) (41,100) — (3,796) (653,634) (495,237) $ $ Based on the average annual book income before taxes for the prior three years, excluding the effects of unusual or infrequent items, the Company believes that the deferred tax assets will be fully realized at current levels of book and taxable income. 82 EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS The Company recognized income tax expense for 2016, 2015 and 2014 as follows (in thousands): Income tax expense: Federal: Current Deferred Total federal income tax State: Current Deferred Total state income tax Generation (amortization) of accumulated investment tax credits Total income tax expense Years Ended December 31, 2016 2015 2014 $ $ 2,642 47,909 50,551 766 3,285 4,051 (684) 53,918 $ $ 2,319 32,819 35,138 1,730 (1,650) 80 (323) 34,895 $ $ (1,250) 38,810 37,560 3,209 641 3,850 (322) 41,088 As of December 31, 2016, the Company had $16.6 million of AMT credit carryforwards that have an unlimited life. As of December 31, 2016, the Company had $59.3 million of federal and $2.2 million of state tax loss carryforwards. If unused, both the federal and state tax loss carryforwards have lives of 20 years and 5 years respectively. As of December 31, 2016, the Company had $0.2 million of unrecognized tax benefits related to stock compensation which cannot be recognized until federal tax loss carryforwards are fully utilized. Income tax provisions differ from amounts computed by applying the statutory federal income tax rate of 35% to book income before federal income tax as follows (in thousands): Federal income tax expense computed on income at statutory rate Difference due to: State taxes, net of federal benefit AEFUDC Permanent tax differences Other Total income tax expense Effective income tax rate Years Ended December 31, 2016 52,740 $ 2015 40,885 2014 46,381 $ $ 2,633 (475) (2,369) 1,389 53,918 $ 52 (2,345) (2,898) (799) 34,895 $ 1,902 (3,757) (2,921) (517) 41,088 35.8% 29.9% 31.0% $ The Company files income tax returns in the United States 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 and New Mexico jurisdictions for years prior to 2012. The Company is currently under audit in Texas for tax years 2007 through 2011. In June 2016, the Arizona Department of Revenue discontinued their audits for tax years 2009 through 2012. The discontinuance of the audits did not have a material impact on the Company's results of operations or financial position. 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 final orders from the PUCT and the NMPRC in its 2015 rate cases, effective January 1, 2016. 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 $5.1 million for the year ended December 31, 2016. 83 EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS In November 2015, the FASB issued new guidance (ASU 2015-17, Balance Sheet Classification of Deferred Taxes) to simplify the presentation of deferred income taxes. ASU 2015-17 requires that deferred tax liabilities and assets be classified as noncurrent in a classified statement of financial position. ASU 2015-17 can be applied prospectively or retrospectively and is effective for financial statements issued for annual periods beginning after December 15, 2016 and interim periods within those annual periods and early adoption is permitted. The Company elected to implement ASU 2015-17 on a retrospective basis for financial statements issued beginning March 31, 2016. The implementation of ASU 2015-17 did not have a material impact on the Company's results of operations. The impact of ASU 2015-17 on the Company's Balance Sheet was to reclassify $21.6 million of current deferred tax assets to long-term deferred tax liabilities at December 31, 2015. 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 $0.4 million (net of an increase of $0.5 million), an unrecognized tax position of $0.8 million, and $2.1 million, in 2016, 2015, and 2014 respectively, related to transmission and distribution costs and other amounts deducted in current and prior year Texas franchise tax returns. The Company recorded a decrease of $0.3 million in 2016 and a decrease of $1.3 million (net of an increase of $0.4 million) in 2014 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, 2016, 2015 and 2014 amounts of unrecognized tax benefits are as follows (in thousands): Balance at January 1 Additions for tax positions related to the current year Reductions for tax positions related to the current year Additions for tax positions of prior years Reductions for tax positions of prior years Balance at December 31 2016 2015 2014 $ $ 6,000 400 — 100 (1,200) 5,300 $ $ 5,200 500 — 300 — 6,000 $ $ 7,200 300 — 2,200 (4,500) 5,200 If recognized, $2.6 million of the unrecognized tax position at December 31, 2016, would reduce the effective tax rate. The Company recognized an income tax benefit for the decrease in unrecognized tax positions of $0.7 million for the year ended December 31, 2016. The Company recognizes in tax expense interest and penalties related to tax benefits that have not been recognized. For the years ended December 31, 2016, 2015, and 2014 the Company recognized interest expense of $0.1 million, $0.2 million, and $0.1 million, respectively. The Company had approximately $0.8 million and $0.7 million accrued for the payment of interest and penalties at December 31, 2016 and 2015, respectively. 84 EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS K. Commitments, Contingencies and Uncertainties Power Purchase and Sale Contracts To supplement its own generation and operating reserve requirements and to meet required renewable portfolio standards, 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 renewable portfolio requirements. The Company has entered into the following significant agreements with various counterparties for the purchase and sale of electricity: Type of Contract Counterparty Quantity Term Power Purchase and Sale Agreement Power Purchase and Sale Agreement Freeport Freeport 25 MW December 2008 through December 2018 100 MW June 2006 through December 2021 Commercial Operation Date N/A N/A Power Purchase Agreement Power Purchase Agreement Power Purchase Agreement Power Purchase Agreement Hatch Solar Energy Center I, LLC 5 MW July 2011 through June 2036 July 2011 NRG 20 MW August 2011 through August 2031 August 2011 SunE EPE1, LLC SunE EPE2, LLC 10 MW 12 MW June 2012 through June 2037 May 2012 through May 2037 June 2012 May 2012 Power Purchase Agreement Macho Springs Solar, LLC 50 MW May 2014 through April 2034 May 2014 Power Purchase Agreement Newman Solar LLC 10 MW December 2014 through November 2044 December 2014 The Company has a firm 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 2018. The Company has entered into several power purchase agreements to help meet its renewable portfolio 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 NRG Solar Roadrunner LLC ("NRG") 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. Furthermore, the Company has a 20-year purchase power 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 purchase power 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 its Newman Power Station ("Newman"). This solar photovoltaic plant began commercial operation in December 2014. 85 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. Environmental Litigation and Investigations. Since July 2011, the U.S. Department of Justice (the "DOJ"), on behalf of the EPA, and APS have been engaged in substantive settlement negotiations in an effort to resolve certain of the pending matters. The allegations being addressed through settlement negotiations are that APS failed to obtain the necessary permits and install the controls necessary under the CAA to reduce sulfur dioxide ("SO2"), nitrogen oxides ("NOx"), and particulate matter ("PM"), and that defendants 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 New Mexico a settlement agreement ("CAA Settlement Agreement") resolving this matter. On August 17, 2015, the U.S. District Court for New Mexico 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, 2016, the Company has accrued its remaining unpaid share of approximately $0.2 million related to this matter. New Mexico Tax Matter Related to Coal Supplied to Four Corners On May 23, 2013, the New Mexico Taxation and Revenue Department ("NMTRD") issued a notice of assessment for coal severance surtax, penalty, and interest totaling approximately $30.0 million related to coal supplied under the coal supply agreement for Four Corners (the "Assessment"). The Company's share of the Assessment is approximately $1.5 million. On behalf of the Four Corners participants, the coal supplier made a partial payment of the Assessment and immediately filed a refund claim with respect to that partial payment in August 2013. The NMTRD denied the refund claim. On December 19, 2013, the coal supplier and APS, on its own behalf and as operating agent for Four Corners, filed complaints with the New Mexico District Court contesting both the validity of the Assessment and the refund claim denial. On June 30, 2015, the court ruled that the Assessment was not valid and further ruled that APS and the other Four Corners co-owners receive a refund of all of the contested amounts previously paid under the applicable tax statute. The NMTRD filed a Notice of Appeal on August 31, 2015 with respect to the decision. Thereafter, APS and the coal supplier entered into a final settlement agreement with the NMTRD with respect to the Assessment. Pursuant to the final settlement agreement, the NMTRD agreed to release the Assessment, dismiss its filed appeal, and release its rights to any other surtax claims with respect to the coal supply agreement. APS and the other Four Corners participants agreed to forgo refund rights with respect to all the contested amounts previously paid under the applicable tax statute, in addition to a $1.0 million settlement payment. The Company paid its share of this settlement, approximately $47,000, in April 2016. Lease Agreements The Company leases land in El Paso, Texas, adjacent to Newman under a lease which expires in June 2033 with a renewal option of 25 years. The Company also has several other leases for office, parking facilities and equipment which expire within the next 4 years. The Company has transmission and distribution lines which are operated under various property easement agreements. The majority of these easements include renewal options which the Company routinely exercises. These lease agreements do not impose any restrictions relating to issuance of additional debt, payment of dividends or entering into other lease arrangements. The Company has no significant capital lease agreements. 86 EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS The Company's total annual rental expense related to operating leases was $1.7 million, $1.9 million, and $1.8 million for 2016, 2015 and 2014, respectively. As of December 31, 2016, the Company’s minimum future rental payments for the next five years are as follows (in thousands): 2017 2018 2019 2020 2021 $ 808 662 666 664 562 Union Matters The Company has approximately 1,100 employees, about 38% 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 the power plants, substations, line crews, meter reading and collection, facilities services, and customer service. The Company entered into a new 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 on September 3, 2018, respectively. L. 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 C and Note K for discussion of the effects of government legislation and regulation on the Company as well as certain pending legal proceedings. 87 EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS M. Employee Benefits Retirement Plans The Company’s Retirement Income Plan (the "Retirement Plan") is a qualified noncontributory defined benefit plan. Upon retirement or death of a vested plan participant, assets of the Retirement Plan are used to pay benefit obligations under the Retirement Plan. Contributions from the Company are based on various factors such as the minimum funding amounts required by the Internal Revenue Service ("IRS"), state and federal regulatory requirements, amounts collected from customers in the Company's Texas and New Mexico jurisdictions and the annual 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 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. During the quarter ended March 31, 2014, the Company implemented certain amendments to the Retirement Plan and Excess Benefit Plan. In the first quarter of 2014, the Company offered a cash balance pension plan as an alternative to its current final average pay pension plan for employees hired prior to January 1, 2014. The cash balance pension plan also included an enhanced employer matching contribution to the employee’s respective 401(k) Defined Contribution Plan (discussed below). For employees that elected the new cash balance feature of the plans, the pension benefit earned under the existing final average pay feature of the plans was frozen as of March 31, 2014. Employees hired after January 1, 2014 were automatically enrolled in the cash balance pension plan. The amendments to the plans were effective April 1, 2014. As a result of these actions, the Company remeasured the assets and liabilities of the plans, based on actuarially determined estimates, using the close of the alternative choice election period of February 28, 2014, as the remeasurement date. 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 plan covers employees beginning on their employment commencement date or re-employment commencement date in any plan year in which the employee completes at least a minimum number of hours of service. Retirement benefits under the cash balance pension plan are based on the employee’s cash balance account, consisting of pay credits and interest credits. The Company complies with the FASB guidance on disclosure for pension and other post-retirement plans that requires disclosure of investment policies and strategies, categories of investment and fair value measurements of plan assets, and significant concentrations of risk. 88 EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS The obligations and funded status of the plans are presented below (in thousands): December 31, 2016 2015 Retirement Income Plan Non-Qualified Retirement Plans Retirement Income Plan Non-Qualified Retirement Plans Change in projected benefit obligation: Benefit obligation at end of prior year Service cost Interest cost Actuarial (gain) loss Benefits paid Benefit obligation at end of year Change in plan assets: $ Fair value of plan assets at end of prior year Actual return (loss) on plan assets Employer contribution Benefits paid Fair value of plan assets at end of year Funded status at end of year $ $ 325,706 7,705 12,161 7,988 (15,792) 337,768 260,035 18,223 7,300 (15,792) 269,766 (68,002) $ $ 26,958 296 878 1,267 (1,937) 27,462 — — 1,937 (1,937) — (27,462) $ $ 341,133 8,530 13,477 (19,290) (18,144) 325,706 272,939 (3,760) 9,000 (18,144) 260,035 (65,671) $ 28,397 262 1,018 (810) (1,909) 26,958 — — 1,909 (1,909) — (26,958) Amounts recognized in the Company's balance sheets consist of the following (in thousands): Current liabilities Noncurrent liabilities Total December 31, 2016 2015 Retirement Income Plan Non-Qualified Retirement Plans Retirement Income Plan Non-Qualified Retirement Plans $ $ — $ (68,002) (68,002) $ (2,696) $ (24,766) (27,462) $ — $ (65,671) (65,671) $ (2,102) (24,856) (26,958) The accumulated benefit obligation in excess of plan assets is as follows (in thousands): December 31, 2016 2015 Projected benefit obligation Accumulated benefit obligation Fair value of plan assets $ Retirement Income Plan (337,768) $ (314,071) 269,766 Non-Qualified Retirement Plans (27,462) $ (25,550) — Retirement Income Plan (325,706) $ (302,446) 260,035 Non-Qualified Retirement Plans (26,958) (25,785) — Pre-tax amounts recognized in accumulated other comprehensive income consist of the following (in thousands): Net loss Prior service benefit Total Years Ended December 31, 2016 2015 Retirement Income Plan 121,052 (23,877) 97,175 $ $ Non-Qualified Retirement Plans $ $ 10,073 (185) 9,888 $ $ Retirement Income Plan 118,963 (27,344) 91,619 Non-Qualified Retirement Plans $ $ 9,592 (224) 9,368 89 EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS The following are the weighted-average actuarial assumptions used to determine the benefit obligations: December 31, 2016 Non-Qualified 2015 Non-Qualified Retirement Income Plan Supplemental Retirement Plan Excess Benefit Plan Retirement Income Plan Supplemental Retirement Plan Excess Benefit Plan Discount rate Rate of compensation increase 4.29% 4.5% 3.76% N/A 4.34% 4.5% 4.57% 4.5% 3.99% N/A 4.59% 4.5% The Company reassesses various actuarial assumptions at least on an annual basis. The discount rate is reviewed at each measurement date. The discount rate used to measure 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, 2016 retirement plans' projected benefit obligation by 11.5%. A 1% decrease in the discount rate would increase the December 31, 2016 retirement plans' projected benefit obligation by 14.1%. The components of net periodic benefit cost are presented below (in thousands): Years Ended December 31, 2016 2015 2014 Retirement Income Plan Non-Qualified Retirement Plans Retirement Income Plan Non-Qualified Retirement Plans Retirement Income Plan Non-Qualified Retirement Plans $ $ 7,705 12,161 (18,879) 6,554 (3,467) 296 878 — 785 (39) $ $ 8,530 13,477 (19,795) $ 262 1,018 — $ 8,284 14,001 (18,699) 9,710 (3,467) 937 (39) 8,178 (2,889) 303 1,041 — 675 (17) $ 4,074 $ 1,920 $ 8,455 $ 2,178 $ 8,875 $ 2,002 Service cost Interest cost Expected return on plan assets Amortization of: Net loss Prior service benefit Net periodic benefit cost In 2016, the Company changed the method used to estimate the service and interest components of net periodic benefit cost for pension benefits. This change, compared to the previous method, resulted in a decrease in the service cost and interest cost components in 2016, and is expected to result in a decrease in the service cost and interest cost components in future periods. Historically, the Company estimated service and interest costs utilizing a single weighted-average discount rate derived from the yield curve used to measure the benefit obligation at the beginning of the period. In 2016, the Company elected to utilize a full yield curve approach to estimate these components by applying the specific spot rates along the yield curve used in the determination of the benefit obligation to the relevant projected cash flows. The Company believes the new approach provides a more precise measurement of service and interest costs by aligning the timing of the plan’s liability cash flows to the corresponding spot rates on the yield curve. The Company accounted for this change as a change in accounting estimate and accordingly, accounted for this prospectively. The change in estimate decreased the service and interest components of net periodic benefit cost in 2016 by approximately $2.9 million. 90 EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS The changes in benefit obligations recognized in other comprehensive income are presented below (in thousands): 2016 2015 2014 Years Ended December 31, Retirement Income Plan Non-Qualified Retirement Plans Retirement Income Plan Non-Qualified Retirement Plans Retirement Income Plan Non-Qualified Retirement Plans $ $ 8,644 — $ 1,266 — $ 4,266 — (811) $ — $ 47,324 (33,700) (6,554) 3,467 (785) 39 (9,710) 3,467 (937) 39 (8,178) 2,889 3,508 (500) (675) 17 $ 5,557 $ 520 $ (1,977) $ (1,709) $ 8,335 $ 2,350 Net (gain) loss Prior service benefit Amortization of: Net loss Prior service benefit Total recognized in other comprehensive income The total amount recognized in net periodic benefit costs and other comprehensive income are presented below (in thousands): Years Ended December 31, 2016 2015 2014 Retirement Income Plan Non-Qualified Retirement Plans Retirement Income Plan Non-Qualified Retirement Plans Retirement Income Plan Non-Qualified Retirement Plans Total recognized in net periodic benefit cost and other comprehensive income $ 9,631 $ 2,440 $ 6,478 $ 469 $ 17,210 $ 4,352 The following are amounts in accumulated other comprehensive income that are expected to be recognized as components of net periodic benefit cost during 2017 (in thousands): Net loss Prior service benefit Retirement Income Plan $ 7,530 (3,470) Non-Qualified Retirement Plans 825 $ (40) The following are the weighted-average actuarial assumptions used to determine the net periodic benefit cost for the twelve months ended December 31: 2016 Non-Qualified 2015 Non-Qualified 2014 (a) Non-Qualified Retirement Income Plan Supplemental Retirement Plan Excess Benefit Plan Retirement Income Plan Supplemental Retirement Plan Excess Benefit Plan Retirement Income Plan Supplemental Retirement Plan Excess Benefit Plan Discount rate Benefit obligation Service cost Interest cost Expected long- term return on plan assets Rate of compensation increase 4.57% 4.83% 3.86% 3.99% 4.63% N/A 4.87% 3.04% 3.9% 4.0% 4.0% 4.0% 3.4% N/A 3.4% 4.1% 4.1% 4.1% 4.9% 4.9% 4.9% 3.9% N/A 3.9% 4.9% 4.9% 4.9% 7.0% N/A N/A 7.5% N/A N/A 7.5% N/A N/A 4.5% N/A 4.5% 4.5% N/A 4.5% 4.75% N/A 4.75% _____________________ (a) The Retirement Plan and the Excess Benefit Plan were remeasured on February 28, 2014 due to the above mentioned plan amendment. The discount rate used to remeasure the benefit obligation was 4.6% for the Retirement Plan and 4.5% for the Excess Benefit Plan, compared to 4.9% for both plans as of January 1, 2014. All other assumptions remained consistent with assumptions used at January 1, 2014. 91 EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS The Company’s overall expected long-term rate of return on assets is 7.0% effective January 1, 2016 and January 1, 2017, 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: Equity securities Fixed income Alternative investments Total December 31, 2016 50% 40% 10% 100% 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 and equity securities of real estate companies. 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 and real estate 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 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. During the third quarter of 2016, the Company concluded that 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 have been re-categorized from Level 2 to Level 1 hierarchy. 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 are 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. 92 EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS The fair value of the Company’s Retirement Plan assets at December 31, 2016 and 2015, 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): Total Common Collective Trusts Limited Partnership Interest in Real Estate (b)(c) Total Plan Investments $ Description of Securities Cash and Cash Equivalents Common Collective Trusts (a) Equity funds Fixed income funds Real Estate Funds Description of Securities Cash and Cash Equivalents Common Collective Trusts (a) Equity funds Fixed income funds Real Estate Funds Fair Value as of December 31, 2016 Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) $ 932 $ 932 $ — $ 144,081 109,356 8,406 261,843 6,991 269,766 144,081 109,356 8,406 261,843 — — — — $ 262,775 $ — $ Fair Value as of December 31, 2015 Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) $ 1,266 $ 1,266 $ — $ 144,279 103,877 2,025 250,181 8,588 260,035 144,279 103,877 2,025 250,181 — — — — $ 251,447 $ — $ — — — — — — — — — — — — Total Common Collective Trusts Limited Partnership Interest in Real Estate (b)(c) Total Plan Investments $ _____________________ (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. In the first quarter of 2016, the Company implemented ASU 2015-07, Fair Value Measurement (Topic 820) which eliminates the requirement to categorize investments in the fair value hierarchy if the fair value is measured at NAV per share (or its equivalent) using the practical expedient in the FASB’s fair value measurement guidance. The fair value amounts presented in the table are intended to permit reconciliation of the fair value hierarchy to the amounts presented in the statement of financial position. ASU 2015-07 is effective for financial statements issued for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. (c) 93 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): Balances at December 31, 2014 Unrealized loss in fair value Balances at December 31, 2015 Sale of land Unrealized loss in fair value Balances at December 31, 2016 Fair Value of Investments in Real Estate $ $ 8,748 (160) 8,588 (775) (822) 6,991 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, 2016 and 2015. 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, 2016 and 2015. The Company adheres to the traditional capital market pricing theory which maintains that over the long term, the risk of owning equities should be rewarded with a greater return than available from fixed income investments. The Company seeks to minimize the risk of owning equity securities by investing in funds that pursue risk minimization strategies and by diversifying its investments to limit its risks during falling markets. The investment manager has full discretionary authority to direct the investment of plan assets held in trust within the guidelines prescribed by the Company through the plan’s investment policy statement including the ability to hold cash equivalents. The investment guidelines of the investment policy statement are in accordance with the Employee Retirement Income Security Act of 1974 ("ERISA") and Department of Labor ("DOL") regulations. The Company contributes at least the minimum funding amounts required by the IRS for the Retirement Plan, as actuarially calculated. The Company expects to contribute at least $10.0 million to its retirement plans in 2017. The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid (in thousands): 2017 2018 2019 2020 2021 2022-2026 Retirement Income Plan $ 16,113 19,080 18,771 18,923 19,755 107,916 Non-Qualified Retirement Plans 2,698 $ 2,060 2,025 1,957 1,907 8,949 401(k) Defined Contribution Plans The Company sponsors 401(k) defined contribution plans covering substantially all employees. Annual matching contributions made to the savings plans for the years 2016, 2015 and 2014 were $4.1 million, $3.9 million, and $3.0 million, respectively. Historically, the Company had provided a 50 percent matching contribution up to 6 percent of the employee’s compensation subject to certain other limits and exclusions. Effective April 1, 2014, for employees who enrolled in the cash balance pension plan (discussed above), the Company provided a 100 percent matching contribution up to 6 percent of the employee's compensation subject to certain other limits and exclusions. Other Post-retirement Benefits The Company provides certain health care benefits for retired employees and their eligible dependents and life insurance benefits for retired employees only. Substantially all of the Company’s employees may become eligible for those benefits if they retire while working for the Company. Contributions from the Company are based on various factors such as the Plan's funded status, the IRS tax deductible limit, state and federal regulatory requirements, amounts collected from customers in the Company's Texas and New Mexico jurisdictions and the annual cost of the Plan, as actuarially calculated. The assets of the 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. 94 EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS The following table contains a reconciliation of the change in the benefit obligation, the fair value of plan assets, and the funded status of the plan (in thousands): Change in benefit obligation: Benefit obligation at end of prior year Service cost Interest cost Actuarial loss (gain) Amendment (a) (b) Benefits paid Retiree contributions Benefit obligation at end of year Change in plan assets: Fair value of plan assets at end of prior year Actual return (loss) on plan assets Employer contribution Benefits paid Retiree contributions Fair value of plan assets at end of year Funded status at end of year December 31, 2016 2015 $ 92,643 2,769 3,167 10,751 (32,697) (4,428) 1,310 73,515 38,090 2,443 1,700 (4,428) 1,310 39,115 (34,400) $ 100,700 3,454 4,035 (11,423) (824) (4,544) 1,245 92,643 41,358 (469) 500 (4,544) 1,245 38,090 (54,553) $ $ _____________________ (a) During October 2016, the Company approved and communicated a plan amendment that resulted in a remeasurement of the Company's Other Post-retirement Benefit Plan. Effective January 1, 2017, retirees and dependents that are less than 65 years of age are 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. (b) Amendment relates to modification of the Company's Other Post-retirement Benefit Plan which increased mail order co- payments for post age 65. The amendment was approved in 2015 and became effective January 1, 2016. Amounts recognized in the Company's balance sheets consist of the following (in thousands): Current liabilities Noncurrent liabilities Total December 31, 2016 2015 $ $ — $ (34,400) (34,400) $ — (54,553) (54,553) Pre-tax amounts recognized in accumulated other comprehensive income consist of the following (in thousands): Net gain Prior service benefit Total December 31, 2016 (26,285) $ (41,009) (67,294) $ 2015 (38,802) (12,213) (51,015) $ $ 95 EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS The following are the weighted-average actuarial assumptions used to determine the accrued post-retirement benefit obligations: Discount rate at end of year Health care cost trend rates: Initial Pre-65 medical Post-65 medical Pre-65 drug Post-65 drug Ultimate Year ultimate reached (a) December 31, 2016 2015 4.36% 4.59% 6.50% 4.50% 7.50% 10.50% 4.50% 2026 7.00% 7.00% 7.00% 7.00% 4.50% 2026 _____________________ (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 discount rate is reviewed 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, 2016 accumulated post-retirement benefit obligation by 13.1%. A 1% decrease in the discount rate would increase the December 31, 2016 accumulated post-retirement benefit obligation by 16.7%. Net periodic benefit cost is made up of the components listed below (in thousands): Service cost Interest cost Expected return on plan assets Amortization of: Prior service benefit Net gain Net periodic benefit cost Years Ended December 31, 2016 2015 2014 $ 2,769 3,167 (1,835) (3,901) (2,374) (2,174) $ 3,454 4,035 (2,070) (3,068) (2,025) 326 $ $ 2,845 4,463 (2,116) (4,753) (2,671) (2,232) $ $ In 2016, the Company changed the method used to estimate the service and interest components of net periodic benefit cost for other post-retirement benefits. This change, compared to the previous method, resulted in a decrease in the service cost and interest cost components in 2016, and is expected to result in a decrease in the service cost and interest cost components in future periods. Historically, the Company estimated service and interest costs utilizing a single weighted-average discount rate derived from the yield curve used to measure the benefit obligation at the beginning of the period. In 2016, the Company elected to utilize a full yield curve approach to estimate these components by applying the specific spot rates along the yield curve used in the determination of the benefit obligation to the relevant projected cash flows. The Company believes the new approach provides a more precise measurement of service and interest costs by aligning the timing of the plan’s liability cash flows to the corresponding spot rates on the yield curve. The Company accounted for this change as a change in accounting estimate and accordingly, accounted for this prospectively. The change in estimate decreased the service and interest components of net periodic benefit cost in 2016 by approximately $0.8 million. 96 EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS The changes in benefit obligations recognized in other comprehensive income are presented below (in thousands): Net (gain) loss Prior service benefit Amortization of: Prior service benefit Net gain Total recognized in other comprehensive income Years Ended December 31, 2016 2015 2014 $ $ $ 10,143 (32,697) (8,884) $ (824) 3,901 2,374 (16,279) $ 3,068 2,025 (4,615) $ 3,496 — 4,753 2,671 10,920 The total amount recognized in net periodic benefit cost and other comprehensive income are presented below (in thousands): Total recognized in net periodic benefit cost and other comprehensive income $ Years Ended December 31, 2016 (18,453) $ 2015 2014 (4,289) $ 8,688 The amount in accumulated other comprehensive income that is expected to be recognized as a component of net periodic benefit cost during 2017 is a prior service benefit of $6.2 million and a net gain of $1.6 million. The following are the weighted-average actuarial assumptions used to determine the net periodic benefit cost for the twelve months ended December 31: Discount rate: Benefit obligation Service cost Interest cost Expected long-term return on plan assets Health care cost trend rates: Initial Ultimate Year ultimate reached 2016 (a) 2015 2014 January 1 - September 30 4.59% 4.91% 3.86% October 1 - December 31 3.75% 4.03% 3.15% 4.875% 7.00% 4.5% 2026 4.1% 4.1% 4.1% 5.2% 7.25% 4.5% 2026 4.9% 4.9% 4.9% 5.2% 7.5% 4.5% 2026 _____________________ (a) The actuarial assumptions are evaluated by the Company at each measurement date. The Other Post-retirement Benefits Plan was remeasured at October 1, 2016 due to a plan amendment. For measurement purposes, a 7.0% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2016. The rate was assumed to decrease gradually to 4.5% for 2026 and remain at that level thereafter. Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plan. The effect of a 1% change in these assumed health care cost trend rates would increase or decrease the December 31, 2016 benefit obligation by $11.2 million or $9.0 million, respectively. In addition, a 1% change in said rate would increase or decrease the aggregate 2016 service and interest cost components of the net periodic benefit cost by $1.3 million or $1.0 million, respectively. 97 EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS The Company’s overall expected long-term rate of return on assets, on an after-tax basis, is 4.875% effective January 1, 2016 and January 1, 2017. 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: Equity securities Fixed income Alternative investments Total December 31, 2016 65% 30% 5% 100% The Other Post-retirement Benefit 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. The asset portfolio also includes cash equivalents and a real estate limited partnership. 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. During the third quarter of 2016, the Company concluded that the NAV used for determining the fair value of the investments in the institutional funds have readily determinable fair values. Accordingly, such fund values have been re-categorized from Level 2 to Level 1 hierarchy. 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 are 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. 98 EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS The fair value of the Company’s Other Post-retirement Benefits Plan assets at December 31, 2016 and 2015, 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): Description of Securities Institutional Funds (a) Equity funds Fixed income funds Total Institutional Funds Limited Partnership Interest in Real Estate (b) (c) Total Plan Investments Description of Securities Institutional Funds (a) Equity funds Fixed income funds Total Institutional Funds Limited Partnership Interest in Real Estate (b) (c) Total Plan Investments Fair Value as of December 31, 2016 Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) $ $ 26,133 11,671 37,804 1,311 39,115 $ $ 26,133 11,671 37,804 — $ — — $ 37,804 $ — $ — — — — Fair Value as of December 31, 2015 Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) $ $ 24,881 11,599 36,480 1,610 38,090 $ $ 24,881 11,599 36,480 — $ — — $ 36,480 $ — $ — — — — ___________________ (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 Company 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. In the first quarter of 2016, the Company implemented ASU 2015-07, Fair Value Measurement (Topic 820) which eliminates the requirement to categorize investments in the fair value hierarchy if the fair value is measured at NAV per share (or its equivalent) using the practical expedient in the FASB’s fair value measurement guidance. The fair value amounts presented in the table are intended to permit reconciliation of the fair value hierarchy to the amounts presented in the statement of financial position. ASU 2015-07 is effective for financial statements issued for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. (c) The table below reflects the changes in the fair value of the investments in real estate during the period (in thousands): Balance at December 31, 2014 Unrealized loss in fair value Balance at December 31, 2015 Sale of land Unrealized loss in fair value Balance at December 31, 2016 Fair Value of Investments in Real Estate 1,640 (30) 1,610 (145) (154) 1,311 $ $ 99 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, 2016 and 2015. 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, 2016 and 2015. The Company adheres to the traditional capital market pricing theory which maintains that over the long term, the risk of owning equities should be rewarded with a greater return than available from fixed income investments. The Company seeks to minimize the risk of owning equity securities by investing in funds that pursue risk minimization strategies and by diversifying its investments to limit its risks during falling markets. The investment manager has full discretionary authority to direct the investment of plan assets held in trust within the guidelines prescribed by the Company through the plan’s investment policy statement including the ability to hold cash equivalents. The investment guidelines of the investment policy statement are in accordance with the ERISA and DOL regulations. The Company expects to contribute $1.5 million to its other post-retirement benefits plan in 2017. The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid (in thousands): 2017 2018 2019 2020 2021 2022-2026 $ 2,622 2,880 3,057 3,320 3,510 20,084 Annual Short-Term Incentive Plan The Annual Short-Term Incentive Plan (the "Incentive Plan") provides for the payment of cash awards to eligible Company employees, including each of its named executive officers. Payment of awards is based on the achievement of performance measures reviewed and approved by the Company’s Board of Directors’ Compensation Committee. Generally, these performance measures are based on meeting certain financial, operational and individual performance criteria. The financial performance goals are based on earnings per share and the operational performance goals are based on compliance, customer satisfaction, and reliability. If a specified level of earnings per share is not attained, no amounts will be paid under the Incentive Plan, unless the Compensation Committee determines otherwise. In 2016, the Company reached the required levels of earnings per share, customer satisfaction, reliability, compliance, and safety goals for an incentive payment of $12.5 million. In 2015 and 2014, the Company reached the required levels of earnings per share, safety, compliance, and customer satisfaction goals for an incentive payment of $10.5 million and $7.4 million, respectively. The Company has renewed the Incentive Plan in 2017 with similar goals. 100 EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS N. 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, which was amended in 2010, the Company pays to the City of El Paso, on a quarterly basis, a fee equal to 4.00% 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 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. 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, 2030. The Company does not have a written franchise agreement with the City of Las Cruces, the second largest city in its service territory. The Company provides electric distribution service to the City of Las Cruces under an implied franchise 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. Military Installations The Company serves HAFB, White Sands Missile Range ("White Sands") and Fort Bliss. These military installations represent approximately 2.8% 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, with HAFB's other power requirements provided under the applicable New Mexico tariffs. 101 EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS O. 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 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): Pollution Control Bonds Senior Notes RGRT Senior Notes (2) RCF (2) Total December 31, 2016 2015 Carrying Amount (1) Estimated Fair Value Carrying Amount (1) Estimated Fair Value $ 190,775 993,086 94,795 81,574 $ 1,360,230 $ 206,818 1,112,285 98,855 81,574 $ 1,499,532 $ 190,499 837,475 94,686 141,738 $ 1,264,398 $ 212,624 829,864 100,345 141,738 $ 1,284,571 __________________ (1) The Company implemented ASU 2015-03, Interest - Imputation of Interest, which requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability. ASU 2015-03 is effective for financial statements issued for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. The impact of ASU 2015-03 on the Company's Balance Sheet was to reclassify $11.6 million of other deferred charges to long-term debt, net of current portion at December 31, 2015. (2) Nuclear fuel financing, as of December 31, 2016 and December 31, 2015, is funded through the $95 million RGRT Senior Notes and $37.6 million and $33.7 million, respectively under the RCF. As of December 31, 2016, $44.0 million was outstanding under the RCF for working capital or general corporate purposes. As of December 31, 2015, $108.0 million amount 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 2017, approximately $0.5 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, 2016, 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. 102 EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS Marketable Securities. The Company’s marketable securities, included in decommissioning trust funds in the balance sheets, are reported at fair value which was $255.7 million and $239.0 million at December 31, 2016 and 2015, respectively. These securities are classified as available for sale and recorded at their estimated fair value using the FASB guidance for certain investments in debt and equity securities. The reported fair values include gross unrealized losses on marketable securities whose impairment the Company has deemed to be temporary. The tables below present the gross unrealized losses and the fair value of these securities, aggregated by investment category and length of time that individual securities have been in a continuous unrealized loss position (in thousands): December 31, 2016 Less than 12 Months 12 Months or Longer Total Fair Value Unrealized Losses Fair Value Unrealized Losses Fair Value Unrealized Losses Description of Securities (1): Federal Agency Mortgage Backed Securities U.S. Government Bonds Municipal Obligations Corporate Obligations Total Debt Securities Common Stock Institutional Funds-International Equity $ $ 11,582 31,655 9,596 7,971 60,804 2,760 22,945 Total Temporarily Impaired Securities $ 86,509 $ ____________________ (1) Includes approximately 152 securities. (239) $ (762) (394) (172) (1,567) (167) (110) 436 17,976 4,067 2,092 24,571 — — (1,844) $ 24,571 $ $ (22) $ 12,018 (835) 49,631 (372) 13,663 (172) 10,063 (1,401) 85,375 2,760 — 22,945 — (1,401) $ 111,080 $ $ (261) (1,597) (766) (344) (2,968) (167) (110) (3,245) December 31, 2015 Less than 12 Months 12 Months or Longer Total Fair Value Unrealized Losses Fair Value Unrealized Losses Fair Value Unrealized Losses $ 9,383 24,094 8,286 6,058 47,821 3,584 22,454 $ 73,859 $ $ (97) $ (310) (160) (722) (1,289) (344) (768) 1,113 14,272 7,388 2,307 25,080 — — (2,401) $ 25,080 $ $ (47) $ 10,496 (623) 38,366 (446) 15,674 (228) 8,365 (1,344) 72,901 3,584 — 22,454 — (1,344) $ 98,939 $ $ (144) (933) (606) (950) (2,633) (344) (768) (3,745) Description of Securities (2): Federal Agency Mortgage Backed Securities U.S. Government Bonds Municipal Obligations Corporate Obligations Total Debt Securities Common Stock Institutional Funds-International Equity Total Temporarily Impaired Securities ______________________ (2) Includes approximately 133 securities. The Company monitors the length of time specific securities trade below its cost basis along with the amount and percentage of the unrealized loss in determining if a decline in fair value of marketable securities below recorded cost is considered to be other than temporary. The Company recognizes impairment losses on certain of its 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. For the twelve months ended December 31, 2016, 2015, and 2014, the Company recognized other than temporary impairment losses on its available-for-sale securities as follows (in thousands): Unrealized holding losses included in pre-tax income 2016 2015 2014 $ (352) $ (338) $ — 103 EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS The reported securities also include gross unrealized gains on marketable securities which have not been recognized in the Company’s net income. The table below presents the unrecognized gross unrealized gains and the fair value of these securities, aggregated by investment category (in thousands): Description of Securities: Federal Agency Mortgage Backed Securities U.S. Government Bonds Municipal Obligations Corporate Obligations Total Debt Securities Common Stock Equity Mutual Funds Cash and Cash Equivalents Total December 31, 2016 December 31, 2015 Fair Value Unrealized Gains Fair Value Unrealized Gains $ $ 7,430 12,237 2,481 12,350 34,498 61,884 42,244 6,002 144,628 $ $ 319 138 144 655 1,256 34,066 3,345 — 38,667 $ $ 9,589 12,033 8,671 10,110 40,403 72,636 18,853 8,204 140,096 $ $ 438 136 332 368 1,274 37,001 91 — 38,366 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, 2016 is as follows (in thousands): Total 2017 2018 through 2021 2022 through 2026 2027 and Beyond Municipal Debt Obligations Corporate Debt Obligations U.S. Government Bonds Federal Agency Mortgage Backed Securities $ $ 16,144 22,413 61,868 19,448 $ 990 — 14,272 — $ 6,253 8,664 22,495 5 $ 8,139 6,090 14,786 390 762 7,659 10,315 19,053 The Company’s marketable securities in its decommissioning trust funds are sold from time to time and the Company uses the specific identification basis to determine the amount to reclassify out of accumulated other comprehensive income and into net income. The proceeds from the sale of these securities during the twelve months ended December 31, 2016, 2015, and 2014 and the related effects on pre-tax income are as follows (in thousands): Proceeds from sales of available-for-sale securities Gross realized gains included in pre-tax income Gross realized losses included in pre-tax income Gross unrealized losses included in pre-tax income Net gains in pre-tax income Net unrealized holding gains (losses) included in accumulated other comprehensive income Net (gains) losses reclassified out of accumulated other comprehensive income Net gains (losses) in other comprehensive income 2016 91,268 9,212 (1,220) (352) 7,640 8,444 (7,640) 804 $ $ $ $ $ 2015 102,567 12,379 (927) (338) 11,114 $ $ $ (2,906) $ (11,114) (14,020) $ 2014 108,311 7,858 (508) — 7,350 10,827 (7,350) 3,477 $ $ $ $ $ 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 104 EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value into three levels as follows: • • • Level 1 - Observable inputs that reflect quoted market prices for identical assets and liabilities in active markets. Financial assets utilizing Level 1 inputs include the nuclear decommissioning trust investments in active exchange-traded equity securities, mutual funds and U.S. Treasury securities that are in a highly liquid and active market. 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. During the third quarter of 2016, the Company concluded that the NAV used for determining the fair value of the Institutional Funds- International Equity investments have readily determinable fair values. Accordingly, such fund values have been re-categorized from Level 2 to Level 1 hierarchy. Level 2 - Inputs other than quoted market prices included in Level 1 that are observable for the asset or liability either directly or indirectly. Financial assets utilizing Level 2 inputs include the nuclear decommissioning trust investments in fixed income securities. The fair value of these financial instruments is based on evaluated prices that reflect observable market information, such as actual trade information of similar securities, adjusted for observable differences. Level 3 - Unobservable inputs using data that is not corroborated by market data and primarily based on internal Company analysis using models and various other analysis. Financial assets utilizing Level 3 inputs are the Company's investment in debt securities. The securities in the Company's decommissioning trust funds are valued using prices and other relevant information generated by market transactions involving identical or comparable securities. 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. The fair value of the Company’s decommissioning trust funds and investments in debt securities at December 31, 2016 and 2015, 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): Description of Securities Trading Securities: Investments in Debt Securities Available for sale: U.S. Government Bonds Federal Agency Mortgage Backed Securities Municipal Obligations Corporate Obligations Subtotal, Debt Securities Common Stock Equity Mutual Funds Institutional Funds-International Equity Cash and Cash Equivalents Total available for sale Fair Value as of December 31, 2016 Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) $ $ $ 1,421 61,868 19,448 16,144 22,413 119,873 64,644 42,244 22,945 6,002 255,708 $ $ $ — $ — $ 1,421 61,868 — — — 61,868 64,644 42,244 22,945 6,002 197,703 $ — $ 19,448 16,144 22,413 58,005 — — — — 58,005 $ $ — — — — — — — — — — 105 EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS Description of Securities Trading Securities: Investments in Debt Securities Available for sale: U.S. Government Bonds Federal Agency Mortgage Backed Securities Municipal Obligations Corporate Obligations Subtotal, Debt Securities Common Stock Equity Mutual Funds Institutional Funds-International Equity Cash and Cash Equivalents Total available for sale Fair Value as of December 31, 2015 Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) $ $ $ 1,543 50,399 20,085 24,345 18,475 113,304 76,220 18,853 22,454 8,204 239,035 $ $ $ — $ — $ 1,543 50,399 — — — 50,399 76,220 18,853 22,454 8,204 176,130 $ — $ 20,085 24,345 18,475 62,905 — — — — 62,905 $ $ — — — — — — — — — — Below is a reconciliation of the beginning and ending balance of the fair value of the investment in debt securities (in thousands): Balance at January 1 Net unrealized gains (losses) in fair value recognized in income (a) $ Balance at December 31 _____________________ (a) These amounts are reflected in the Company's statements of operations as investment and interest income. $ 2016 2015 1,543 (122) 1,421 $ $ 1,653 (110) 1,543 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, 2016 and 2015. 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, 2016 and 2015. 106 EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS P. Supplemental Statements of Cash Flows Disclosures Cash paid for: Interest on long-term debt and borrowing under the revolving credit facility Income taxes, net of refund Non-cash investing and financing activities: Sale of Interest in Four Corners Generating Station (a) Changes in accrued plant additions Grants of restricted shares of common stock Years Ended December 31, 2016 2015 2014 (In thousands) $ 69,990 $ 62,297 $ 2,328 1,000 27,720 4,789 1,236 — (6,660) 1,567 54,792 6,876 — 7,314 3,025 (a) The Company sold its interest in Four Corners for approximately $32.0 million based on the book value as defined in the Purchase and Sale Agreement. The sales price was adjusted downward by $7.0 million and $19.5 million to reflect APS's affiliate assumption of the Company's obligation to pay for future plant decommissioning and mine reclamation expense, respectively. The sales price was also adjusted downward by approximately $1.3 million for closing adjustments and other assets and liabilities assumed by APS's affiliate. At the closing of the sale, the Company received approximately $4.2 million in cash, subject to post-closing adjustments. 107 EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS Q. Selected Quarterly Financial Data (Unaudited) The following table summarizes the Company’s unaudited results of operations on a quarterly basis. The quarterly earnings per share amounts for a year will not add to the earnings per share for that year due to the weighting of shares used in calculating per share data. Operating revenues (1) Operating income (loss) Net income (loss) Basic earnings per share: Net income (loss) Diluted earnings per share: Net income (loss) Dividends declared per share of common stock 2016 Quarters 2015 Quarters 4th 3rd (2) 2nd 1st 4th 3rd 2nd 1st (In thousands except for share data) $188,037 $323,225 $217,865 20,470 129,857 5,656 74,636 44,697 22,284 $157,809 (163) (5,808) $176,902 $289,713 $219,508 $163,746 8,312 648 88,047 56,740 41,872 21,072 7,960 3,458 0.14 1.84 0.55 (0.14) 0.02 1.40 0.52 0.09 0.14 1.84 0.55 (0.14) 0.02 1.40 0.52 0.09 0.310 0.310 0.310 0.295 0.295 0.295 0.295 0.280 ________________ (1) Operating revenues are seasonal in nature, with the peak sales periods generally occurring during the summer months. Comparisons among quarters of a year may not represent overall trends and changes in operations. (2) 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 PUCT Final Order on August 25, 2016. Accordingly, it reported in the third quarter of 2016 the cumulative effect of the PUCT Final Order which related back to January 12, 2016. See Part II, Item 8, Financial Statements and Supplementary Data, Note C. 108 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure None. 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, 2016, 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 49 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, 2016, that materially affected, or that were reasonably likely to materially affect, our internal control over financial reporting. Item 9B. Other Information None. The information set forth in Part III and Part IV has been omitted from this Annual Report to Shareholders. PART III and PART IV 109     EVOLUTION POWER INNOVATION 

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