Excelerate Energy
Annual Report 2013

Plain-text annual report

2013 ANNUAL REPORT Live life brightly. It’s more than a short powerful tagline, it’s an attitude… an expression of our confidence that says we are moving forward and making big strides as a company. It also shows our commitment to make improvements to the grid by building new facilities and integrating new technology. For our customers, it’s a statement that assures them that the power will be on when they need it, but it’s also an invitation, a call to action, to live their lives brightly. Power On. is a rallying cry, a service promise and a pledge to our community that says we, the people of El Paso Electric, will be there whenever and wherever they need us. So go ahead. POWER ON. DEAR EE INVESTORS, CUSTOMERS, REGULATORS AND ALL INTERESTED STAKEHOLDERS, For over 100 years, El Paso Electric (“EE” or the “Company”) has been dedicated to the long-term success and well-being of our region. Our over 1,000 local employees, management team and Board of Directors are committed to continuing our history of anticipating and investing in the plant, equipment and facilities required to provide economical, clean and reliable energy for our growing region’s needs. Accordingly, several years ago, EE began planning and investing to replace its aging plant and equipment, some of which continues to operate beyond its initially expected useful life. In the case of our largest source of generation, our 633 megawatt (MW) interest in Palo Verde which provides 46% of our power, we are pleased that the useful life of the three units has been extended by 20 years each so they will now operate until 2045, 2046 and 2047. However, much of our fossil fuel generation is already more than 50 years old and is based on dated, less efficient technology. In the past 5 years, we have spent almost one billion dollars for the replacement of plant and equipment, as well as for additional generation, transmission and distribution plant to serve the growth in our communities. This included the construction of the Company’s first new power plants in almost 30 years – the 288 MW Newman 5 natural gas-fired combined cycle plant to serve base load needs and the 87 MW Rio Grande Unit 9, a quick start natural gas-fired simple cycle unit. To continue to serve the growth of our communities and replace antiquated plant and equipment, we expect to spend an additional $1.3 billion in the next 5 years. This will include the construction of the new Montana Power Station as well as new transmission and distribution lines to meet our region’s needs. As always, we are planning and managing our expenditures to ensure we are good stewards of our customers’ hard-earned dollars and the capital entrusted to us by our investors. We appreciate the trust placed in us by our stakeholders as we provide for the current and future needs of our customers and the communities we serve. Our ability to serve our customers over time requires EE to ensure its financial strength by achieving a fair return on its invested capital, which in the coming years will require the first significant net base rate increase in 20 years. 2013 solidified EE’s role as a leader in renewable energy and sustainable practices. Because we have the good fortune to be located in the high mountain desert of the Southwest, and due to the reduction in the cost of solar panels, we have been able to incorporate significant utility scale solar generation into our portfolio at a cost competitive with conventional fossil fuel alternatives. The use of utility scale solar provides the most economic solar option for our customers and also allows all of our customers to benefit from this powerful resource. In 2014, the addition of 60 megawatts of solar energy, added as a system resource at a competitive price compared to other fuel sources, will more than double the amount of solar energy used to serve all our 394,000 customers. Environmental stewardship implemented economically for our customers is among our top priorities. We are proud that our generation portfolio makes EE one of the industry’s cleanest utilities with one of the lowest carbon footprints in the country for a utility of our size. As committed as we are to developing our renewable portfolio, the vibrant, growing communities we serve in west Texas and southern New Mexico require reliable generation available 24 hours a day. Our vision for providing safe, clean, affordable and reliable energy is through the addition of state-of-the-art natural gas-fired generation and cost competitive renewables as depicted on the cover of this report. This carefully designed mix of solar and local clean burning natural gas generation will provide our customers, hardworking families and businesses with the energy they need to prosper and be safe 24 hours a day, seven days a week. ANNUAL REPORT 2013 EL PASO ELECTRIC The Company’s 2013 accomplishments provide clear examples of our commitment to meeting the region’s needs. First, Chairman of the Board, Kenneth Heitz. These endowments will be used for scholarships to promising students and also include internship opportunities at EE. we continued to make significant progress on our capital construction programs. During 2013, we expended $237 million in We provide internships for younger students as well and, for the second year in a row, a group of 14 area high school students worked for the Company additions to utility property, plant and equipment. These necessary investments will enable us to continue to meet our customers’ over the summer. In addition to these programs, we provided grants to over 150 local non-profit organizations. A vast majority of these non-profits were expectations for cost effective, clean and reliable electrical service. In addition to the commercial operation of Rio Grande Unit 9 chosen because one or more of our employees is actively involved in the organization, and we see a direct connection to the long-term betterment of and the planned additional 60 MW of solar energy mentioned above, other accomplishments include: our communities from their work. Our employees contributed more than 15,000 hours of community service in 2013.The positive impact from this • The construction of a new 7-mile transmission line designed to meet growing energy needs and ensure reliability in southern New Mexico; dedication, along with the financial commitment from EE, cannot be overstated. The year was not without challenges. On the regulatory front, due to the delays in receiving the permits for the Montana Power Station, we have revised • The start of construction of a new Distribution Operations Center designed to enhance response time and customer service, the projected dates for the commercial operation of Montana Power Station Units 1 and 2 to the second quarter of 2015. As a result, the Company which is scheduled for completion in early 2015; and • The opening of a new customer service office in downtown El Paso. currently expects to file a request to increase base rates in 2015 in both Texas and New Mexico. The anticipated need for rate recovery is necessitated predominantly by the increase in our net invested capital driven by the replacement of plant and equipment as well as growth in power requirements. This includes investments in Rio Grande Unit 9, which became operational in May 2013, and the Montana Power Station Units 1 and 2, which are In 2013, despite some initial delays in the permitting process, we successfully obtained the necessary permits from the state of currently scheduled to be operational by June 2015. EE has also made significant investments in transmission and distribution plant to enable it to meet Texas for the Montana Power Station, our new $372 million state-of-the art local generation facility. This 352 MW four-unit power the region’s growing needs. station will serve approximately 160,000 homes and will also utilize the quick-start, natural gas-fired technology used in our recently completed Rio Grande Unit 9. The Montana Power Station will provide EE the ability to reliably and economically support In 2013, we also experienced a decline in non-fuel base revenues for the twelve months ended December 31, 2013, as compared to the corresponding additional renewable generation resources in the future. The final permit needed to begin construction, a greenhouse gas permit, period in the prior year. This decline was due to less favorable weather during our 2013 summer cooling season and lower revenues from governmental was obtained from the Environmental Protection Agency (EPA) in March 2014 and will become effective 30 days from the date customers. Additionally, our revenues for the twelve months ended December 31, 2013 reflected a carryover impact of the reduction in non-fuel base of issuance unless it is appealed. We are currently on track to bring the first two units of the power station online by summer of rates for our Texas customers which became effective May 1, 2012. These factors contributed to a decline in earnings from $2.27 per basic share in 2015, in order to meet the growing energy needs of the communities we serve in a timely manner. 2012 to $2.20 per basic share in 2013. After careful analysis, EE has determined that it is in the best interest of its customers not to participate in extending the operation Since 2008, EE’s stock price has appreciated at a compound annual growth rate of over 14% notwithstanding 2013’s earnings decline. In 2013, of the almost 50-year-old coal-fired Four Corners Power Generating Station after the plant’s scheduled retirement in July 2016. EE distributed a total of $42 million in cash dividends and increased its quarterly cash dividend by 6% to $0.265 per share (from $0.25 per share) in We believe there are more economical alternatives for meeting our customers’ needs. EE, which has a 7% interest in Units 4 and the second quarter of 2013. This is the second consecutive year in which the Company has increased the quarterly cash dividend since the dividend 5 of the plant, will continue to work with the other owners and the Navajo Nation to facilitate their efforts to extend their operation program was re-initiated in 2011. EE continues to maintain a healthy balance sheet which is viewed favorably by the financial community. Standard and of the plant beyond 2016. Also, Arizona Public Service Company has expressed an interest in buying EE’s stake. Upon our exit Poor’s reaffirmed its BBB issuer credit rating and stable outlook on October 10, 2013. On January 20, 2014, Moody’s upgraded EE’s senior unsecured from Four Corners, we will no longer own coal-fired generation. and issuer credit ratings to Baa1 from Baa2. In 2013, our employees once again proved that their focus, dedication, and commitment are keys to reliable service. For three As has been the trend for many years, 2013 again saw an increase in the number of customers served by EE. We anticipate that such growth will continue. consecutive years, EE has received the highest reliability rankings for investor-owned utilities in Texas for the System Average 2014 will continue the challenging, but rewarding, work of building new infrastructure for our growing communities. We are reminded every day of the Interruption Duration Index (SAIDI) and the System Average Interruption Frequency Index (SAIFI), as compiled by the Public Utility great strides made by both EE as well as by our region and, more importantly, of our potential. Our service territory is gifted with extraordinary sunshine Commission of Texas. And again this year, our crews had the opportunity to demonstrate their dedication and commitment to helping others by assisting crews of Public Service Company of New Mexico in restoring electricity to our neighbors after a devastating summer storm. We are not only stepping up to the challenge of meeting our communities’ energy needs, we are also working to positively influence our region in other ways as well. Not surprisingly, many questions and concerns were raised regarding many of our infrastructure development projects. We worked with community groups and private citizens to ensure they had the accurate information they needed in order to understand our projects, the need for them, and the impact on their communities. As always, EE is working to be a good corporate citizen that will positively impact the communities where we work and serve. We look forward to strong, enduring partnerships with our stakeholders based on transparency, respect, and trust as we enter this next phase. We appreciate how fortunate we are to serve our region. There are countless examples of how EE and its employees fulfill their commitment to making our communities better places to live and work, through both financial contributions and, often more importantly, by contributing their time. While far too many to describe, 2013’s contributions included two $250,000 endowment gifts to the engineering departments of New Mexico State University and the University of Texas at El Paso, in honor of our late to power economical utility scale solar facilities; the benefits of serving two growing states; sharing a border with the thriving and resilient community of Juarez, Mexico; two universities producing a high-caliber work force; and the local military institutions of Fort Bliss in Texas and White Sands Missile Range and Holloman Air Force Base in New Mexico. Every day, the entire EE team is working to provide reliable and economical power to our customers now and for the future, to generate appropriate returns for our shareholders and to make our communities and our Company even better places to live and work. On behalf of the EE team, we thank all our stakeholders for the opportunity to serve. Thomas V. Shockley III Chief Executive Officer Michael K. Parks Chairman of the Board ANNUAL REPORT 2013 BOARD OF DIRECTORS Michael K. Parks Retired Managing Director Crescent Capital Group, LP and Business Consultant, Los Angeles, CA Chairman of the Board El Paso Electric Company, El Paso, TX Edward Escudero President and Chief Executive Officer High Desert Capital, LLC, El Paso, TX Thomas V. Shockley, III Chief Executive Officer El Paso Electric Company, El Paso, TX Catherine A. Allen Founder, Chairman and Chief Executive Officer The Santa Fe Group, Santa Fe, NM James W. Harris Managing Partner OP Food Products LLC and Harris Financial Advisors, LLC, Manns Harbor, NC Eric B. Siegel Retired Limited Partner of Apollo Advisors, LP Consultant and Special Advisor to the Chairman of the Milwaukee Brewers Baseball Club, Los Angeles, CA J. Robert Brown Owner and President Brownco Capital, LLC, El Paso, TX Patricia Z. Holland-Branch Owner, Chairman and Chief Executive Officer The Facilities Connection, Inc., El Paso, TX Stephen N. Wertheimer Managing Director and Founding Partner W Capital Partners, New York, NY James W. Cicconi Senior Executive Vice President External and Legislative Affairs, AT&T Washington, D.C. Woodley L. Hunt Chairman and Chief Executive Officer Hunt Companies, Inc., El Paso, TX Charles A. Yamarone Managing Director Houlihan Lokey, Los Angeles, CA OFFICERS Thomas V. Shockley, III Chief Executive Officer David G. Carpenter Executive Vice President Hector R. Puente Executive Vice President Steven T. Buraczyk Senior Vice President Operations Nathan T. Hirschi Senior Vice President Chief Financial Officer Mary E. Kipp Senior Vice President General Counsel and Chief Compliance Officer Rocky R. Miracle Senior Vice President Corporate Planning and Development David C. Hawkins Vice President Power Marketing & Fuels and Resource Delivery & Planning William A. Stiller Senior Vice President Human Resources and Customer Care Kerry B. Lore Vice President Customer Care Michael D. Blanchard Vice President Regulatory Affairs Steven P. Busser Vice President Treasurer Andres R. Ramirez Vice President Power Generation Guillermo Silva, Jr. Vice President Community Outreach Robert C. Doyle Vice President Transmission & Distribution and System Operations & Planning H. Wayne Soza Vice President Compliance and Chief Risk Officer 2013 PERFORMANCE HIGHLIGHTS EL PASO ELECTRIC Financial ($000) Operating Revenues Retail Non-Fuel Base Revenues Deregulated Palo Verde Unit 3 Proxy Market Off-System Sales Gross Margins Retained Margins Net Income Total Assets Common Stock Data Earnings Per Share (diluted weighted average) Market Price Per Share (year end close) Book Value Per Share Common Stock Equity Shares Outstanding at End of Year Weighted Average Number of Shares 2011 2012 2013 $569,956 $14,820 $3,323 $(560) $103,539 $560,282 $9,848 $10,289 $1,098 $90,846 $556,498 $11,423 $14,565 $1,549 $88,583 $2,396,851 $2,669,050 $2,786,288 2011 2012 2013 $2.48 $34.64 $19.03 $760,251 39,959,154 $2.26 $31.91 $20.57 $2.20 $35.11 $23.44 $824,999 40,112,078 $943,833 40,266,706 and Dilutive Potential Shares Outstanding 41,587,059 40,055,581 40,126,647 Number of Registered Holders as of 12/31 3,340 2,767 2,680 ANNUAL REPORT 2013 OPERATING STATISTICS OPERATING REVENUES (in thousands): 2013 2012 2011 2010 2009 2008 2007 2006 2005 2004 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 (Economy) Sales: Fuel Cost Shared Margins Retained Margins Total Off-System Sales Other: Total Operating Revenues Number of Customers (End of Year): (a) Residential Commercial and Industrial, Small Commercial and Industrial, Large Other Total Average Annual kWh Use per Residential Customer Energy Sales, MWh: Generated Purchased and Interchanged Total Energy Supplied Energy Sales, MWh: Retail: Residential Commercial and Industrial, Small Commercial and Industrial, Large Sales to Public Authorities Total Retail Wholesale: Sales for Resale Off-System (economy) Sales Total Wholesale Total Energy Sales Losses and Company Use Total, Net Native System: Peak Load, MW Net Dependable Generating Capability for Peak, MW Total System: Peak Load, MW Net Dependable Generating Capability for Peak, MW $236,651 184,568 40,235 95,044 556,498 2,172 558,670 133,481 10,849 73,295 217,625 68,241 13,016 1,549 82,806 31,261 $890,362 349,629 39,164 50 5,043 393,886 7,701 9,288,773 1,547,930 10,836,703 2,679,262 2,349,148 1,095,379 1,622,607 7,746,396 61,232 2,472,622 2,533,854 10,280,250 556,453 10,836,703 1,750 1,852 1,883 1,852 $234,095 188,014 42,041 96,132 560,282 2,318 562,600 130,193 (18,539) 74,154 185,808 62,481 9,191 1,098 72,770 31,703 $852,881 345,567 38,494 50 4,896 389,007 7,712 9,262,133 1,768,810 11,030,943 2,648,348 2,366,541 1,082,973 1,617,606 7,715,468 64,266 2,614,132 2,678,398 10,393,866 637,077 11,030,943 1,688 1,765 1,979 1,765 $234,086 196,093 45,407 94,370 569,956 2,122 572,078 145,130 13,917 73,454 232,501 74,736 3,883 (560) 78,059 35,375 $918,013 339,860 38,539 49 4,720 383,168 7,804 8,936,776 2,135,124 11,071,900 2,633,390 2,352,218 1,096,040 1,579,565 7,661,213 62,656 2,687,631 2,750,287 10,411,500 660,400 11,071,900 1,714 1,785 1,967 1,785 $217,615 188,390 43,844 86,460 536,309 1,943 538,252 170,588 (35,408) 71,876 207,056 93,516 6,114 5,687 105,317 26,626 $877,251 334,729 37,202 50 4,841 376,822 7,560 8,465,659 2,420,869 10,886,528 2,508,834 2,295,537 1,087,413 1,542,389 7,434,173 53,637 2,822,732 2,876,369 10,310,542 575,986 10,886,528 1,616 1,643 1,889 1,643 $195,798 175,328 34,804 77,370 483,300 2,037 485,337 196,081 (66,608) 69,026 198,499 101,665 3,596 10,803 116,064 28,096 $827,996 328,553 36,306 48 4,964 369,871 7,244 7,979,290 2,745,500 10,724,790 2,361,650 2,251,399 1,024,186 1,482,448 7,119,683 56,931 2,995,984 3,052,915 10,172,598 552,192 10,724,790 1,571 1,643 1,723 1,643 $184,800 174,593 36,318 74,427 470,138 1,646 471,784 198,292 42,752 68,631 309,675 203,021 7,342 22,137 232,500 24,971 $1,038,930 322,618 35,850 49 4,935 363,452 6,955 8,023,475 3,152,396 11,175,871 2,227,838 2,255,585 1,102,277 1,448,654 7,034,354 50,148 3,506,770 3,556,918 10,591,272 584,599 11,175,871 1,524 1,503 1,669 1,503 $184,562 168,091 39,092 72,763 464,508 1,919 466,427 197,383 17,828 51,487 266,698 106,393 4,067 15,514 125,974 18,328 $877,427 317,091 35,147 53 4,853 357,144 7,085 7,707,095 2,188,904 9,895,999 2,232,668 2,216,428 1,195,038 1,384,380 7,028,514 48,290 2,201,294 2,249,584 9,278,098 617,901 9,895,999 1,508 1,492 1,680 1,492 $175,641 161,359 40,502 68,438 445,940 1,794 447,734 225,441 (3,655) 30,033 251,819 73,331 4,340 18,261 95,932 20,970 $816,455 311,923 32,950 58 4,800 349,731 6,852 6,908,006 2,208,661 9,116,667 2,113,733 2,159,599 1,204,707 1,343,129 6,821,168 45,397 1,635,407 1,680,804 8,501,972 614,695 9,116,667 1,428 1,492 1,675 1,492 $173,007 158,406 39,192 65,861 436,466 1,687 438,153 164,500 79,539 29,440 273,479 57,943 6,516 13,750 78,209 14,072 $803,913 304,031 31,969 61 4,792 340,853 6,936 7,500,144 1,255,626 8,755,770 2,090,098 2,126,918 1,165,506 1,270,116 6,652,638 41,883 1,420,778 1,462,661 8,115,299 640,471 8,755,770 1,376 1,479 1,628 1,479 $164,791 157,188 41,096 65,351 428,426 1,675 430,101 143,692 17,360 27,956 189,008 57,268 8,250 13,015 78,533 10,986 $708,628 296,435 31,079 58 4,553 332,125 6,769 7,611,455 1,410,114 9,021,569 1,986,085 2,115,822 1,236,426 1,243,003 6,581,336 41,094 1,838,467 1,879,561 8,460,897 560,672 9,021,569 1,332 1,472 1,575 1,472 (a) The number of retail customers presented for 2012 and 2011 have been revised based on the number of service locations. Previously the number of retail customers for 2012 and 2011 were based on the number of bills rendered including consolidated bills for customers operating multiple facilities. Management believes that the number of service locations provides a more accurate indicator of customers served than the number of bills rendered. ANNUAL REPORT 2013 2013 OPERATIONAL HIGHLIGHTS Total Shareholder Return Five-Year Cumulative Comparison $230 $210 $190 $170 $150 $130 $110 $90 $70 $50 $30 $209 $205 $131 $110 Dec. 31, 2008 Dec. 31, 2009 Dec. 31, 2010 Dec. 31, 2011 Dec. 31, 2012 Dec. 31, 2013 EE S&P 500 Utilities S&P 500 Electric S&P 500 $100 $100 $100 $100 $112 $107 $99 $123 $152 $108 $97 $139 $194 $124 $112 $139 $184 $120 $106 $158 $209 $131 $110 $205 Assumes $100 was invested in El Paso Electric Company common stock and each index listed above on December 31, 2008 and assumes that all dividends were reinvested. Market Price Per Share (Year-End) Common Stock Equity (Year-End) Annual Value of Share Repurchases and Dividends ($000) 2013 2012 2011 2010 2009 $35.11 $31.91 $34.64 $27.53 $20.28 2013 2012 2011 2010 2009 48% 45% 46% 49% 46% 2013 2012 2011 2010 2009 $42,049 $38,889 $113,731 (a) $33,726 $24,105 (a) EE Initiated a quarterly cash dividend in 2011 distributing a total of $27.2mm in addition to $86.5mm in share repurchases EL PASO ELECTRIC 2013 Retail MWh Sales Operational 2011 2012 2013 Retail GWh Sold % Change Native Peak (MW) 7,661 3.05% 1,714 7,715 0.70% 1,688 7,746 0.40% 1,750 Customers at Year-End (a) 383,168 389,007 393,886 % Change Employees at Year-End 1.68% 984 1.52% 985 1.25% 1,005 (a) The number of retail customers presented are based on the number of service locations. Previous presentations of the number of retail customers in 2012 and 2011 were based on the number of bills rendered including consolidated fills for customers operating multiple facilities. Management believes the number of service locations provides a more accurate indicator of customers served than the number of bills rendered. Palo Verde Capacity Factor 91% 2011 90% 2010 92% 2012 89% 2009 91% 2013 Residential Commercial & Ind. Small Commercial & Ind. Large Sales to Public Authorities 35% 30% 14% 21% 2013 Retail Non-Fuel Base Operating Revenues Residential Commercial & Ind. Small Commercial & Ind. Large 43% 33% 7% Sales to Public Authorities 17% 2014-2018 Construction Cost Estimates (in millions) Production Transmission Distribution General $584 $193 $317 $180 Total $1,274 2013 Generating Capacity and Energy Mix Palo Verde Newman Rio Grande Copper Four Corners Renewables Nuclear Natural Gas Natural Gas Natural Gas Coal Purchased Power Wind/Solar Generating Capacity = 633 MW 732 MW 316 MW 62 MW 108 MW 1 MW Energy Mix = 46% 34% 6% 14% Total Generating Capacity = 1,852 MW ANNUAL REPORT 2013 SERVICE TERRITORY MAP Hatch Las Cruces El Paso Van Horn Generation Station Capacity (MW) Newman Power Station ∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙ 732 Rio Grande Power Station ∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙ 316 Copper Power Station∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙ 62 Palo Verde Power Station ∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙ 633 Four Corners Power Station ∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙ 108 Montana Power Station ∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙ 352 (Future Facility) SOLAR FACILITIES MAP EL PASO ELECTRIC Solar Facility Capacity (kW) Newman Solar Station ∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙ 64.3 Newman Solar Project (Dec 2014) ∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙ 10,000.0 Rio Grande Solar Station ∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙ 64.3 Wrangler Solar Facility ∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙ 48.0 Stanton Tower Solar Installation ∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙ 31.4 El Paso Community College ∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙ 14.5 Van Horn Solar Installation ∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙ 17.4 Hatch Solar Energy Center ∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙ 5,000.0 NRG Solar Roadrunner Generating Facility∙∙∙∙∙∙ 20,000.0 El Chaparral Solar Farm ∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙ 10,000.0 Las Cruces Centennial Solar Farm ∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙ 12,000.0 Macho Springs Solar Facility (May 2014)∙∙∙∙∙∙∙∙ 50,000.0 To Albuquerque, NM Four Corners, NM (400 miles) To Springerville, AZ New Mexico Diablo Holloman AFB Palo Verde, AZ (450 miles) White Sands Missile Range Amrad Eddy County, NM Interchange (125 miles) Luna Las Cruces Arroyo Newman McGregor Range Anthony Montana Rio Grande Ascarate Caliente Diablo Copper To Dell City, TX Texas Fabens Ciudad Juárez Sierra Blanca Van Horn México Generating Station Major Distribution Stations Company Lines 25 Hatch 85 11 26 Macho Springs 10 506 Las Cruces 54 85 Vado 10 Anthony Chaparral Sunland Park Ciudad Juárez Canutillo 10 El Paso Fort Bliss 180 375 Socorro Van Horn San Elizario 10 90 EL PASO ELECTRIC INVESTOR RELATIONS Securities and Records The common stock of El Paso Electric is traded on the New York Stock Exchange. The ticker symbol is EE. EE and Computershare Shareowner Services act as co-registrars for EE’s common stock. Computershare Shareowner Services maintains all shareholder records of EE. Form 10-K Report and Shareholder Inquiries A complete copy of EE’s Annual Report and Form 10-K for the year ending December 31, 2013, which has been filed with the Securities and Exchange Commission, including financial statements and financial statement schedules, is available without charge upon written request to: Investor Relations El Paso Electric P.O. Box 982 El Paso, TX 79960 Call: (800) 592-1634 Email: investor_relations@epelectric.com Website: epelectric.com Shareowner Services Shareholders may obtain information relating to their share position, transfer requirements, lost certifi- cates and other related matters by contacting Computershare Shareowner Services at (866) 202-2682 (inside the United States and Canada), (201) 680-6578 (outside the United States and Canada), or (800) 231-5469 (TDD) for the hearing impaired. The phone service is available to all shareholders Monday through Friday, 8 a.m. to 8 p.m., EST. Address shareowner inquires to: El Paso Electric Company C/O Computershare P.O. Box 43006 Providence, RI 02940-3006 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, 2013 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, 2013, the aggregate market value of the voting stock held by non-affiliates of the registrant was $1,401,286,283 (based on the closing price as quoted on the New York Stock Exchange on that date). As of January 31, 2014, there were 40,279,810 shares of the Company’s no par value common stock outstanding. Portions of the registrant’s definitive Proxy Statement for the 2014 annual meeting of its shareholders are incorporated by reference DOCUMENTS INCORPORATED BY REFERENCE into Part III of this report. Table of Contents 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..................................................... Arizona Public Service Company ASU.................................................... Accounting Standards Update Company ............................................ El Paso Electric Company DOE.................................................... United States Department of Energy El Paso................................................ City of El Paso, Texas FASB.................................................. Financial Accounting Standards Board FERC.................................................. Federal Energy Regulatory Commission Fort Bliss ............................................ Fort Bliss the United States Army post next to El Paso, Texas Four Corners....................................... Four Corners Generating Station kV ....................................................... kW ...................................................... Kilovolt(s) Kilowatt(s) kWh .................................................... Kilowatt-hour(s) Las Cruces .......................................... City of Las Cruces, New Mexico MW..................................................... Megawatt(s) MWh................................................... NERC ................................................. North American Electric Reliability Corporation NMPRC.............................................. New Mexico Public Regulation Commission Megawatt-hour(s) Net dependable generating capability The maximum load net of plant operating requirements which a generating plant can supply under specified conditions for a given time interval, without exceeding approved limits of temperature and stress NRC.................................................... Nuclear Regulatory Commission Palo Verde........................................... Palo Verde Nuclear Generating Station Palo Verde Participants....................... Those utilities who share in power and energy entitlements, and bear certain allocated costs, with respect to Palo Verde pursuant to the ANPP Participation Agreement PNM ................................................... Public Service Company of New Mexico PUCT.................................................. Public Utility Commission of Texas RGEC ................................................. RGRT.................................................. Rio Grande Electric Cooperative Rio Grande Resources Trust TEP..................................................... Tucson Electric Power Company (i) Table of Contents Item TABLE OF CONTENTS Description PART I 1 Business ........................................................................................................................................... 1A 1B 2 3 Risk Factors ..................................................................................................................................... Unresolved Staff Comments ............................................................................................................ Properties ......................................................................................................................................... Legal Proceedings ........................................................................................................................... 4 Mine Safety Disclosures .................................................................................................................. PART II 5 Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities ............................................................................................................................ 6 Selected Financial Data ................................................................................................................... 7 Management's Discussion and Analysis of Financial Condition and Results of Operations ........... 7A Quantitative and Qualitative Disclosures About Market Risk ......................................................... 8 9 9A 9B Financial Statements and Supplementary Data ............................................................................... Changes in and Disagreements with Accountants on Accounting and Financial Disclosure .......... Controls and Procedures .................................................................................................................. Other Information ............................................................................................................................ PART III ........................................................................................................................................ PART IV ......................................................................................................................................... Page 1 16 21 21 21 21 22 25 26 42 44 97 97 97 97 97 (ii)  Table of Contents FORWARD-LOOKING STATEMENTS Certain matters discussed in this Annual Report on Form 10-K other than statements of historical information are "forward-looking statements." The Private Securities Litigation Reform Act of 1995 has established that these statements qualify for safe harbors from liability. Forward-looking statements may include words like we "believe", "anticipate", "target", "expect", "pro forma", "estimate", "intend", "will", "is designed to", "plan" and words of similar meaning. Forward-looking statements describe our future plans, objectives, expectations or goals. Such statements address future events and conditions concerning and include, but are not limited to, such things as: • • • • • • • • • • • • 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 involve known and unknown risks that may cause our actual results in future periods to differ materially from those expressed in any forward-looking statement. Factors that would cause or contribute to such differences include, but are not limited to, such things as: • • • • • • • • • • • • • • • our ability to recover our costs and earn a reasonable rate of return on our invested capital through the rates that we charge, the ability of our operating partners to maintain plant operations and manage operation and maintenance costs at the Palo Verde and Four Corners plants, including costs to comply with any potential new or expanded regulatory or environmental requirements, reductions in output at generation plants operated by us, unscheduled outages of generating units including outages at Palo Verde, the size of our construction program and our ability to complete construction on budget, potential delays in our construction schedule due to legal or other reasons, disruptions in our transmission system, and in particular the lines that deliver power from our remote generating facilities, electric utility deregulation or re-regulation, regulated and competitive markets, ongoing municipal, state and federal activities, economic and capital market conditions, changes in accounting requirements and other accounting matters, changing weather trends and the impact of severe weather conditions, rates, cost recovery mechanisms and other regulatory matters including the ability to recover fuel costs on a timely basis, changes in environmental laws and regulations and the enforcement or interpretation thereof, including those related to air, water or greenhouse gas emissions or other environmental matters, (iii) Table of Contents • • • • • • • • • • • • • changes in customers' demand for electricity as a result of energy efficiency initiatives and emerging competing services and technologies, cuts in military spending or shutdowns of the federal government that reduce demand for our services from military and governmental customers, political, legislative, judicial and regulatory developments, the impact of lawsuits filed against us, the impact of changes in interest rates, 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 recent U.S. health care reform legislation, the impact of changing cost escalation and other assumptions on our nuclear decommissioning liability for Palo Verde, Texas, New Mexico and electric industry utility service reliability standards, homeland security considerations, including those associated with the U.S./Mexico border region, 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 IRS or state taxing authorities, 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" "–Summary of Critical Accounting Policies and Estimates" and "–Liquidity and Capital Resources." This report should be read in its entirety. No one section of this report deals with all aspects of the subject matter. Any forward-looking statement speaks only as of the date such statement was made, and we are 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) Table of Contents 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 1,852 MW. For the year ended December 31, 2013, the Company’s energy sources consisted of approximately 46% nuclear fuel, 34% natural gas, 6% coal, 14% purchased power and less than 1% generated by Company-owned solar photovoltaic panels and wind turbines. The Company's current generation portfolio exhibits lower carbon intensity than any other utility in the southwestern United States and the Company continues to expand its portfolio of renewable energy sources, particularly solar photovoltaic generation. As of December 31, 2013, the Company has power purchase agreements for 107 MW from solar photovoltaic generation facilities. (See "Energy Sources- Purchased Power"). The Company serves approximately 394,000 residential, commercial, industrial, public authority and wholesale customers. The Company distributes electricity to retail customers principally in El Paso, Texas and Las Cruces, New Mexico (representing approximately 62% and 12%, respectively, of the Company’s retail revenues for the year ended December 31, 2013). In addition, the Company’s wholesale sales include sales for resale to other electric utilities and power marketers. Principal industrial, public authority and other large retail customers of the Company include United States military installations, including Fort Bliss in Texas and White Sands Missile Range and Holloman Air Force Base in New Mexico, an oil refinery, two large universities, several medical centers 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, 2014, the Company had approximately 1,000 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, and all amendments to those reports as soon as reasonably practicable after such material is electronically filed with or furnished to the Securities and Exchange Commission ("SEC"). In addition, copies of the annual report will be made available free of charge upon written request. The SEC also maintains an internet site that contains reports, proxy and information statements and other information for issuers that file electronically with the SEC. The address of that site is www.sec.gov. The information on the Company's website is not incorporated into this document by reference. As of December 31, 2013, the Company’s net dependable generating capability of 1,852 MW consists of the following: Facilities Station Palo Verde Station Newman Power Station Rio Grande Power Station Four Corners Station (Units 4 and 5) Copper Power Station Renewables Total Primary Fuel Type Nuclear Natural Gas Natural Gas Coal Natural Gas Wind/Solar Company's Share of Net Dependable Generating Capability * (MW) Company Ownership Interest Location 633 732 316 108 62 1 1,852 15.8% 100% Wintersburg, Arizona El Paso, Texas 100% Sunland Park, New Mexico 7% Fruitland, New Mexico 100% 100% El Paso, Texas Hudspeth/El Paso Counties, Texas ____________________ * During summer peak period. Company owned renewables include a wind ranch with a total capacity of 1.32 MW and six solar photovoltaic facilities with a total capacity of 0.2 MW. 1 Table of Contents Palo Verde Station The Company owns an interest, along with six other utilities, in the three nuclear generating units and common facilities ("Common Facilities") at Palo Verde. Arizona Public Service Company ("APS") serves as operating agent for Palo Verde, and under the ANPP Participation Agreement, the Company has limited ability to influence operations and costs at Palo Verde. • License Extension. In 2011, the NRC renewed the operating licenses for all three units at Palo Verde. The renewed licenses for Units 1, 2 and 3 now expire in 2045, 2046 and 2047, respectively. • 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, 2013, the Company's decommissioning trust fund had a balance of $214.1 million. 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. • Spent Fuel Storage. 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. APS (on behalf of itself and the other Palo Verde participants) filed a lawsuit for DOE's breach of the spent nuclear fuel contract in the U.S. Court of Federal Claims. The Court of Federal Claims ruled in favor of APS and in October 2010 awarded $30.0 million in damages to the Palo Verde participants for costs incurred through December 2006. In October 2010, the Company received $4.8 million, representing its share of the award. The majority of the award was refunded to customers through the applicable fuel adjustment clauses. On December 19, 2012, APS, acting on behalf of itself and the participant owners of Palo Verde, filed a second breach of contract lawsuit against the DOE. This lawsuit seeks to recover damages incurred due to DOE's failure to accept Palo Verde's spent nuclear fuel for the period beginning January 1, 2007 through June 30, 2011.The lawsuit is presently pending in the Court of Federal Claims. The DOE had planned to meet its disposal obligations by designing, licensing, constructing, and operating a permanent geologic repository at Yucca Mountain, Nevada. In March 2010, the DOE filed a motion to dismiss with prejudice its Yucca Mountain construction authorization application that was pending before the NRC. Several interested parties have intervened in the NRC proceeding, and the proceeding has not been conclusively decided by the NRC or the courts. Additionally, a number of interested parties have filed a variety of lawsuits in different jurisdictions around the country challenging the DOE's authority to withdraw the Yucca Mountain construction authorization application and NRC’s cessation of its review of the Yucca Mountain construction authorization application. The cases have been consolidated into one matter at 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. The Company cannot predict when spent fuel shipments to the DOE will commence. APS and the Company believe that spent fuel storage or disposal methods will be available to allow each Palo Verde unit to continue to operate through the current term of its operating license. The Company expects to incur significant costs for on-site spent fuel storage during the life of Palo Verde which the Company believes are the responsibility of the DOE. These costs are assigned to fuel requiring the additional on-site storage and amortized as that fuel is burned until an agreement is reached with the DOE for recovery of these costs. • NRC Oversight of the Nuclear Energy Industry in the Wake of the Earthquake and Tsunami in Japan. The NRC regulates the operation of all commercial nuclear power reactors in the United States, including Palo Verde. The NRC periodically conducts inspections of nuclear facilities and monitors performance indicators to enable the agency to arrive at objective conclusions about a licensee's safety performance. Following the March 11, 2011 earthquake and tsunami in Japan, 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. 2 Table of Contents The NRC has issued a series of interim staff guidance documents regarding implementation of these requirements. Due to the developing nature of these requirements, the Company cannot predict the ultimate financial or operational impacts on Palo Verde or the Company; however, the NRC has directed nuclear power plants to implement the first tier recommendations of the NRC’s Near Term Task Force. In response to these recommendations, Palo Verde expects to spend approximately $100 million for capital enhancements to the plant over the next several years (the Company's share is $15.8 million). • 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 million. The Palo Verde Participants also maintain "all risk" (including nuclear hazards) insurance for property damage to, and decontamination of, property at Palo Verde. In addition, the Company has secured insurance against portions of any increased cost of generation or purchased power and business interruption resulting from a sudden and unforeseen outage at Palo Verde. Fossil-Fueled Plants The Newman Power Station consists of three steam-electric generating units and two combined cycle generating units. The station operates primarily on natural gas but the conventional steam-electric generating units can also operate on fuel oil. The Company's Rio Grande Power Station consists of three steam-electric generating units and one aeroderivative unit which operate on natural gas. The Company owns a 7% interest in Units 4 and 5 at Four Corners Generating Station ("Four Corners"). The Company shares power entitlements and certain allocated costs of the two units with APS (the Four Corners operating agent) and the other Four Corners participants. Four Corners is located on land under easements from the federal government and a lease from the Navajo Nation that expires in 2016. APS, on behalf of the Four Corners participants, negotiated amendments to the lease with the Navajo Nation which extended the lease from 2016 to 2041, pending the approval of the Department of the Interior and a Federal environmental review. The 50-year participation agreement among the owners of Four Corners expires by its terms in July 2016. The Company has notified the other owners that it has decided to cease its participation in the plant by July 2016. The Company believes that it has better economic and cleaner alternatives for serving the energy needs of its customers than coal-fired generation. The Company has nevertheless agreed to work with the other owners and the Navajo Nation in an attempt to facilitate their efforts to extend the operation of the plant beyond July 2016 in a manner consistent with protecting the Company's ratepayers. In December 2013, the other owners executed a long-term extension of the coal supply agreement for the plant through 2031. The Company did not sign the extension and APS has agreed to assume the resulting 7% shortfall and has also expressed an interest in acquiring the Company’s interest in Four Corners. The Company's Copper Power Station consists of a combustion turbine used primarily to meet peak demand. Wind and Solar Photovoltaic Facilities The Company’s Hueco Mountain Wind Ranch consists of two wind turbines with a total capacity of 1.32 MW. 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, three 500 kV lines in Arizona, and owns the transmission and distribution network within its New Mexico and Texas retail service area and operates these facilities under franchise agreements with various municipalities. The Company is also a party to various transmission and power exchange agreements that, together with its owned transmission lines, enable the Company to deliver its energy entitlements from its remote generation sources at Palo Verde and Four Corners to its service area. Pursuant to standards established by the North American Electric Reliability Corporation and the Western Electricity Coordinating Council, the Company operates its transmission system in a way that allows it to maintain system integrity in the event that any one of these transmission lines is out of service. 3 Table of Contents In addition to the transmission and distribution lines within our service territory, the Company's transmission network and associated substations include the following: Line Length (miles) Voltage (kV) Springerville-Macho Springs-Luna-Diablo Line (1) West Mesa-Arroyo Line (2) Greenlee-Hidalgo-Luna-Newman Line (3) Greenlee-Hidalgo Hidalgo-Luna Luna-Newman Eddy County-AMRAD Line (4) Palo Verde Transmission Palo Verde-Westwing (5) Palo Verde-Jojoba-Kyrene (6) 310 202 60 50 86 125 45 75 345 345 345 345 345 345 500 500 Company Ownership Interest 100.0% 100.0% 40.0% 57.2% 100.0% 66.7% 18.7% 18.7% ____________________ (1) Runs from TEP's Springerville Generating Plant near Springerville, Arizona, to the Company's Diablo Substation near Sunland Park, New Mexico. (2) Runs from PNM's West Mesa Substation located near Albuquerque, New Mexico, to the Company's Arroyo Substation located near Las Cruces, New Mexico. (3) Runs from TEP's Greenlee Substation near Duncan, Arizona to the Newman Power Station. (4) Runs from the Company's and PNM's high voltage direct current terminal at the Eddy County Substation near Artesia, New Mexico to the AMRAD Substation near Oro Grande, New Mexico. Due to damage caused by severe weather conditions which occurred in November and December of 2013, this transmission line is not currently in service. The Company cannot currently predict when this line will return to service. (5) Represents two 45-mile, 500 kV lines running from Palo Verde to the Westwing Substation located northwest of Phoenix near Peoria, Arizona. (6) Runs from Palo Verde to the Jojoba Substation located near Gila Bend, Arizona, then to the Kyrene Substation located near Tempe, Arizona. Environmental Matters General. The Company is subject to extensive laws, regulations and permit requirements with respect to air and greenhouse gas 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 Company's operations, including sulfur dioxide ("SO2"), particulate matter ("PM"), nitrogen oxides ("NOx") and mercury. Clean Air Interstate Rule/Cross State Air Pollution Rule. The U.S. Environmental Protection Agency's (the "EPA") Clean Air Interstate Rule ("CAIR"), as applied to the Company since 2009, 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. While the U.S. Court of Appeals for the District of Columbia Circuit voided CAIR in 2008, on appeal the rule was reinstated until such time as the EPA promulgates a replacement rule. Because the appellate court in August 2012 also vacated the EPA’s proposed replacement, which is called the Cross-State Air Pollution Rule ("CSAPR"), CAIR remains in effect. On March 29, 2013, the U.S. Solicitor General petitioned the U.S. Supreme Court to review the D.C. Circuit's decision to vacate CSAPR. On June 24, 2013, 4 Table of Contents the Supreme Court agreed to hear the case, and oral arguments were heard on December 10, 2013. The timing and outcome of the Supreme Court decision is unknown, and in the meantime, the Company remains subject to CAIR. National Ambient Air Quality Standards. Under the CAA, the EPA sets National Ambient Air Quality Standards ("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 NOx and SO2. In December 2012, the EPA tightened the NAAQS for fine PM, and it is expected to propose more stringent ozone NAAQS in 2014 (with a final rule in 2015). The Company continues to evaluate what impact these final and proposed NAAQS could have on its operations. If the Company is required to install additional equipment to control emissions at its facilities, the revised NAAQS could have a material impact on its operations and financial results. Utility MACT. The operation of coal-fired power plants, such as the Company's Four Corners plant, results in emissions of mercury and other air toxics. In December 2011, the EPA finalized Mercury and Air Toxics Standards (known as the "Utility MACT") for oil-and coal-fired power plants, which requires significant reductions in emissions of mercury and other air toxics. Several judicial and other challenges are being made to this rule. These challenges notwithstanding, companies impacted by the new standards will generally have up to three years to comply. Information from the Four Corners plant operator, APS, indicates that APS currently believes Units 4 and 5 will require no additional modifications to achieve compliance with the Utility MACT standards. Other Laws and Regulations and Risks. As stated above, the Company intends to cease its participation in Four Corners at the expiration of the 50-year participation agreement in 2016. The Company believes that it has better economic and cleaner alternatives for serving the energy needs of its customers than coal-fired generation, which is subject to extensive regulation and litigation. For example, as a result of APS’s recent Best Available Retrofit Technology Federal Implementation Plan compliance strategy notification to the EPA, Four Corners is required to install expensive pollution control equipment in order to continue operation in the future. The Company’s share of the cost of these controls is currently estimated by APS to be approximately $39 million if the Company were to extend its participation in the plant. In addition, the EPA has entered into a consent decree which would require it to sign for publication a final action regarding the regulation of coal combustion residuals ("CCR") under the federal Resource, Conservation and Recovery Act by December 19, 2014. Once issued, the Company may be required to incur significant costs to address CCRs either generated in the past and disposed of at or from Four Corners, as well as CCRs generated in connection with the ongoing operations of Four Corners. Further, assured supplies of water are important for the Company's operations and assets, including Four Corners. Four Corners is located in a region that has been experiencing drought conditions which could affect the plant’s water supply. Four Corners has accordingly been involved in negotiations and proceedings with third parties relating to water supply issues. The drought conditions and related negotiations and proceedings could adversely affect the amount of power available, or the price thereof, from Four Corners. Climate Change. The U.S. federal government has either considered, proposed and/or finalized legislation or regulations limiting greenhouse gas ("GHG") emissions, including carbon dioxide. In particular, the U.S. Congress periodically considers 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 applied to the Company, as well as the EPA’s 2010 actions to impose permitting requirements on new and modified sources of GHG emissions, which may create significant costs for power plant owners and operators. On June 25, 2013, President Obama set forth his plan to address climate change. He reiterated a goal of reducing GHG "in the range of 17 percent" below 2005 levels by 2020. The plan included a variety of executive actions, including future regulatory measures to reduce carbon emissions from power plants. In a White House memorandum of the same date, the President directed the EPA to issue a new proposal for GHG rulemaking addressing new power plants by September 20, 2013, and a rule for existing power plants by June 1, 2014. The formal proposal for new power plants was published in the Federal Register on January 8, 2014. The Company continues its review of the new proposal and plans to participate in the 60-day post-publication comment period. Given the very significant remaining uncertainties regarding these rules, the Company believes it is impossible to meaningfully quantify the costs of these potential requirements at present. In addition, almost half the U.S. states, either individually and/or through multi-state regional initiatives, have begun to consider how to address GHG emissions and have developed, or are actively considering the development of emission inventories or regional GHG cap and trade programs. While a significant portion of the Company's generation assets are nuclear or gas-fired, and as a result, the Company believes that its greenhouse gas emissions are low relative to electric power companies who rely more on coal-fired generation, current and future legislation and regulation of GHGs or any future related litigation could impose significant costs and/or operating restrictions on the Company, reduced demand for the power the Company generates and/or 5 Table of Contents require the Company to purchase rights to emit GHGs, any of which could be material to the Company's business, financial condition, reputation or results of operations. Climate change also has potential physical effects that could be relevant to the Company's business. In particular, some studies suggest that climate change could affect the Company's service area by causing higher temperatures, less winter precipitation and less spring runoff, as well as by causing more extreme weather events. Such developments could change the demand for power in the region and could also impact the price or ready availability of water supplies or affect maintenance needs and the reliability of Company equipment. The Company believes that material effects on the Company's business or results of operations may result from the physical consequences of climate change, the regulatory approach to climate change ultimately selected and implemented by governmental authorities, or both. Given the very significant remaining uncertainties regarding whether and how these issues will be regulated, as well as the timing and severity of any physical effects of climate change, the Company believes it is impossible to meaningfully quantify the costs of these potential impacts at present. Environmental Litigation and Investigations. Since 2009, the EPA and certain environmental organizations have been scrutinizing, and in some cases, have filed lawsuits, relating to certain air emissions and air permitting matters related to Four Corners. In particular, 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. In March 2012, the DOJ provided APS with a draft consent decree to settle the EPA matter, which decree contains specific provisions for the reduction and control of NOx, SO2, and PM, as well as provisions for a civil penalty, and expenditures on environmental mitigation projects with an emphasis on projects that address alleged harm to the Navajo Nation. Settlement discussions are on-going and the Company is unable to predict the outcome of these settlement negotiations. The Company received notice that Earthjustice filed a lawsuit in the United States District Court for New Mexico on October 4, 2011 for alleged violations of the Prevention of Significant Deterioration ("PSD") provisions of the CAA related to Four Corners. On January 6, 2012, Earthjustice filed a First Amended Complaint adding claims for violations of the CAA's New Source Performance Standards ("NSPS") program. Among other things, the plaintiffs seek to have the court enjoin operations at Four Corners until APS applies for and obtains any required PSD permits and complies with the referenced NSPS program. The plaintiffs further request the court to order the payment of civil penalties, including a beneficial mitigation project. On April 2, 2012, APS and the other Four Corners' participants filed motions to dismiss with the court. The case is being held in abeyance while the parties seek to negotiate a settlement. On March 30, 2013, upon joint motion of the parties, the court issued an order deeming the motions to dismiss withdrawn without prejudice during pendency of the stay. At such time as the stay is lifted, APS, the Company and the other Four Corners participants may reinstate the motions to dismiss. On February 14, 2014, the parties filed a joint motion to extend the stay in the case by 30 days holding the matter in abeyance until March 17, 2014. The Company is unable to predict the outcome of this litigation. Construction Program Utility construction expenditures reflected in the following table consist primarily of local generation, expanding and updating the transmission and distribution systems, and the cost of capital improvements and replacements at Palo Verde. Studies indicate that the Company will need additional power generation resources to meet increasing load requirements on its system and to replace retiring plants and terminated purchased power agreements, the costs of which are included in the table below. The Company’s estimated cash construction costs for 2014 through 2018 are approximately $1.3 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) 2014................................................... $ 2015................................................... 2016................................................... 2017................................................... 2018................................................... Total ........................................... $ 327 256 249 209 233 1,274 6 By Function (estimates in millions) Generation (1)(2) ........................ $ Transmission............................... Distribution ................................. General (3) .................................. 584 193 317 180 Total..................................... $ 1,274 Table of Contents __________________________ (1) Does not include acquisition costs for nuclear fuel. See "Energy Sources – Nuclear Fuel." (2) $345 million has been allocated for new generating capacity of which $214 million is to construct four units of the Montana Power Station (the "MPS"). The $214 million consist of $63 million to complete construction of two 88 MW gas-fired LMS-100 units that are scheduled to come on line before the summer peak in 2015 and $151 million for two additional 88 MW gas fired LMS-100 units scheduled to come on line before the summer peak in 2016 and 2017. An additional $17 million of common costs is associated with the development of the MPS. The construction costs for the four units of the MPS may increase, and the construction schedule, associated expenditures and the in-service dates could be delayed, if the Company does not receive non-appealable air permits by the end of the third quarter of 2014. For a full discussion of the MPS air permits see "Regulation-Texas Regulatory Matters- Montana Power Station Approvals". In addition to the construction costs for the MPS, $114 million of construction costs are included from 2016 through 2018 for a combined cycle unit scheduled to be phased in over the 2019 to 2021 time frame. In addition to construction costs for new generating capacity, generation costs include $44 million for other local generation, $16 million for Four Corners (which excludes costs for pollution control equipment that would be placed in service after the Company’s planned exit in July 2016), and $179 million for the Palo Verde Station. The Company currently intends to retire Rio Grande Power Station Unit 6 (“Rio Grande 6”) before the 2015 summer peak. Rio Grande 6 is a 45 MW steam-electric generating unit which was originally placed in service in 1957. The Company may decide to extend the life of Rio Grande 6 should the construction schedule of MPS be delayed. Additionally, as noted above, the Company intends to cease its participation in Four Corners in 2016. Includes $33 million for a new distribution center, which will be located at the MPS. (3) 7 Table of Contents 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. Years Ended December 31, Power Source Nuclear ................................................................. Natural gas............................................................ Coal ...................................................................... Purchased power .................................................. Total............................................................... 2013 2011 2012 (percentage of energy mix) 46% 34 6 14 100% 46% 32 6 16 100% 45% 30 6 19 100% 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 "– New Mexico Regulatory Matters." Nuclear Fuel The nuclear fuel cycle for Palo Verde consists of the following stages: the mining and milling of uranium ore to produce uranium concentrates; the conversion of the uranium concentrates to uranium hexafluoride ("conversion services"); the enrichment of uranium hexafluoride ("enrichment services"); the fabrication of fuel assemblies ("fabrication services"); the utilization of the fuel assemblies in the reactors; and the storage and disposal of the spent fuel. Pursuant to the ANPP Participation Agreement, the Company owns an undivided interest in nuclear fuel purchased in connection with Palo Verde. The Palo Verde participants are continually identifying their future nuclear fuel resource needs and negotiating arrangements to fill those needs. The Palo Verde participants have contracted for 100% of Palo Verde's requirements for uranium concentrates through 2017, 90% of its requirements in 2018 and 45% of its requirements in 2019-2020. The participants have also contracted for all of Palo Verde's conversion services through 2016 and 95% of its requirements in 2017-2018 and 45% of its requirements in 2019-2020. In addition, all of Palo Verde's enrichment services through 2020 have been contracted and all of Palo Verde's fuel assembly fabrication services through 2016 are under contract. Nuclear Fuel Financing. The Company’s financing of nuclear fuel is accomplished through Rio Grande Resources Trust ("RGRT"), a Texas grantor trust, which is consolidated in the Company’s financial statements. RGRT has $110 million aggregate principal amount borrowed through senior notes. The Company guarantees the payment of principal and interest on the senior notes. The nuclear fuel financing requirements of RGRT are met with a combination of the senior notes and amounts borrowed under the revolving credit facility (the "RCF"). Natural Gas The Company manages its natural gas requirements through a combination of a long-term supply contract and spot market purchases. The long-term supply contract provides for firm deliveries of gas at market-based index prices. In 2013, the Company’s natural gas requirements at the Newman and Rio Grande Power Stations were met with both short-term and long-term natural gas purchases from various suppliers, and this practice is expected to continue in 2014. Interstate gas is delivered under a base firm transportation contract. The Company has expanded its firm interstate transportation contract to include the 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 the Newman and Rio Grande Power Stations. The Company will continue to evaluate the availability of short-term natural gas supplies versus long-term supplies to maintain a reliable and economical supply for the Newman and Rio Grande Power Stations. Natural gas for the Newman and Copper Power Stations is also supplied pursuant to an intrastate natural gas contract that became effective October 1, 2009 and continues through 2017. 8 Table of Contents Coal APS, as operating agent for Four Corners, purchases Four Corners' coal requirements from a supplier with a long-term lease of coal reserves owned by the Navajo Nation. On December 30, 2013, APS and Southern California Edison ("SCE") closed their previously announced transaction whereby APS agreed to purchase SCE's 48% interest in Units 4 and 5 of Four Corners. Concurrently with the closing of this transaction, the ownership of BHP Navajo Coal Company, the coal supplier and operator of the mine that serves Four Corners, was transferred to Navajo Transitional Energy Company, LLC ("NTEC"), a company formed by the Navajo Nation to own the mine and develop other energy projects. The 50-year participation agreement among the owners of Four Corners expires by its terms in July 2016. The Company has notified the other owners that it has decided to cease its participation in the plant by July 2016. The Company believes that it has better economic and cleaner alternatives for serving the energy needs of its customers than coal-fired generation. The Company has nevertheless agreed to work with the other owners and the Navajo Nation in an attempt to facilitate their efforts to extend the operation of the plant beyond July 2016 in a manner consistent with protecting the Company's ratepayers. In December 2013, the other owners executed a long-term extension of the coal supply agreement for the plant through 2031. The Company did not sign the extension and APS has agreed to assume the resulting 7% shortfall and has also expressed an interest in acquiring the Company’s interest in Four Corners. Purchased Power To supplement its own generation and operating reserves and to meet required renewable portfolio standards, the Company engages in power purchase arrangements which may vary in duration and amount based on evaluation of the Company’s resource needs, the economics of the transactions and specific renewable portfolio requirements. The Company has a firm Power Purchase and Sale Agreement with Freeport-McMoran Copper and Gold Energy Services LLC ("Freeport") which provides for Freeport to deliver energy to the Company from its ownership interest in the Luna Energy Facility (a natural gas fired combined cycle generation facility located in Luna County, New Mexico) and for the Company to deliver a like amount of energy at Greenlee, Arizona. The Company may purchase up to 125 MW at a specified price at times when energy is not exchanged under the Power Purchase and Sale Agreement. Upon mutual agreement, the contract allows the parties to increase the amount of energy that is purchased and sold under the Power Purchase and Sale Agreement. The parties have agreed to increase the amount to 125 MW through December 2014. The contract was approved by the FERC and continues through December 31, 2021. The Company entered into an agreement in 2009 to purchase capacity of up to 40 MW and unit contingent energy during 2010 from Shell Energy North America ("Shell"). Under the agreement, the Company provides natural gas to Pyramid Unit No. 4 where Shell has the right to convert natural gas to electric energy. The Company entered into a contract with Shell on May 17, 2010 to extend the term of the capacity and unit contingent energy purchase from January 1, 2011 through September 30, 2014. The Company entered into a 20-year contract with NRG Solar Roadrunner, LLC ("NRG") for the purchase of all of the output of a 20 MW solar photovoltaic plant built in southern New Mexico which began commercial operation in August 2011. The Company has a 25-year purchase power agreement with Hatch Solar Energy Center I, LLC for a 5 MW solar photovoltaic project located in southern New Mexico which began commercial operation in July 2011. The Company has 25-year purchase power agreements to purchase all of the output of two additional solar photovoltaic projects located in southern New Mexico, SunEdison 1 (10 MW) and SunEdison 2 (12 MW) which achieved commercial operation on June 25, 2012 and May 2, 2012, respectively. The Company entered into these contracts to help meet its renewable portfolio requirements. In May 2013, the NMPRC approved the Company's 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. The term of the purchased power agreement is 20 years from the commercial operation date of the Macho Springs project which is projected to be May 1, 2014. In addition, on September 5, 2013, the Company entered into a purchased power agreement with Newman Solar LLC to purchase, for a term of 30 years, the total output from a solar photovoltaic generation facility of approximately 10 MW that Newman Solar LLC will construct, own and operate on land subleased from the Company in proximity to its Newman Generation Station. This solar project is expected to be on line at the end of 2014. Other purchases of shorter duration were made during 2013 to supplement the Company's generation resources during planned and unplanned outages and for economic reasons as well as to supply off-system sales. 9 Table of Contents Operating Statistics 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 .............................................................................................................. Total operating revenues........................................................ $ Number of customers (end of year) (1): Residential...................................................................................................... Commercial and industrial, small .................................................................. Commercial and industrial, large................................................................... Other .............................................................................................................. Total ....................................................................................... Average annual kWh use per residential customer ............................................... Energy supplied, net, kWh (in thousands): Years Ended December 31, 2012 2011 2013 $ $ 236,651 184,568 40,235 95,044 556,498 2,172 558,670 133,481 10,849 73,295 217,625 68,241 13,016 1,549 82,806 31,261 890,362 349,629 39,164 50 5,043 393,886 7,701 $ $ 234,095 188,014 42,041 96,132 560,282 2,318 562,600 130,193 (18,539) 74,154 185,808 62,481 9,191 1,098 72,770 31,703 852,881 345,567 38,494 50 4,896 389,007 7,712 234,086 196,093 45,407 94,370 569,956 2,122 572,078 145,130 13,917 73,454 232,501 74,736 3,883 (560) 78,059 35,375 918,013 339,860 38,539 49 4,720 383,168 7,804 Generated ....................................................................................................... Purchased and interchanged........................................................................... Total ....................................................................................... 9,288,773 1,547,930 10,836,703 9,262,133 1,768,810 11,030,943 8,936,776 2,135,124 11,071,900 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 ....................................................................................... 2,679,262 2,349,148 1,095,379 1,622,607 7,746,396 61,232 2,472,622 2,533,854 10,280,250 556,453 10,836,703 Native system: Peak load, kW ................................................................................................ Net dependable generating capability for peak, kW...................................... 1,750,000 1,852,000 Total system: Peak load, kW (2) .......................................................................................... Net dependable generating capability for peak, kW...................................... 1,883,000 1,852,000 2,648,348 2,366,541 1,082,973 1,617,606 7,715,468 64,266 2,614,132 2,678,398 10,393,866 637,077 11,030,943 1,688,000 1,765,000 1,979,000 1,765,000 2,633,390 2,352,218 1,096,040 1,579,565 7,661,213 62,656 2,687,631 2,750,287 10,411,500 660,400 11,071,900 1,714,000 1,785,000 1,967,000 1,785,000 ___________________________ (1) The number of retail customers presented are based on the number of service locations. Previous presentations of the number of retail customers in 2012 and 2011 were based on the number of bills rendered including consolidated bills for customers operating multiple facilities. Management believes the number of service locations provides a more accurate indicator of customers served than the number of bills rendered. Includes spot sales and net losses of 133,000 kW, 291,000 kW and 253,000 kW for 2013, 2012 and 2011, respectively. (2) 10 Table of Contents General Regulation The rates and services of the Company are regulated by incorporated municipalities in Texas, the PUCT, the NMPRC, and the FERC. The PUCT and the NMPRC have jurisdiction to review municipal orders, ordinances and utility agreements regarding rates and services within their respective states and over certain other activities of the Company. The FERC has jurisdiction over the Company's wholesale (sales for resale) transactions, transmission service and compliance with federally-mandated reliability standards. The decisions of the PUCT, the NMPRC and the FERC are subject to judicial review. Texas Regulatory Matters 2012 Texas Retail Rate Case. The Company filed a rate increase request with the PUCT, Docket No. 40094, the City of El Paso, and other Texas cities on February 1, 2012. The rate filing was made in response to a resolution adopted by the El Paso City Council (the "Council") requiring the Company to show cause why its base rates for customers in the El Paso city limits should not be reduced. The filing at the PUCT also included a request to reconcile $356.5 million of fuel expense for the period July 1, 2009 through September 30, 2011. On April 17, 2012, the Council approved the settlement of the Company's 2012 Texas retail rate case and fuel reconciliation in PUCT Docket No. 40094. The PUCT issued a final order approving the settlement on May 23, 2012. Under the terms of the settlement, among other things, the Company agreed to: • A reduction in its non-fuel base rates of $15 million annually, with the decrease being allocated primarily to Texas retail commercial and industrial customer classes. The rate decrease was effective as of May 1, 2012; • Revised depreciation rates for the Company's gas-fired generating units and for transmission and distribution plant that lower depreciation expense by $4.1 million annually; • Continuation of the 10.125% return on equity for the purpose of calculating the allowance for funds used during construction; and • A two-year amortization of rate case expenses, none of which will be included in future regulatory proceedings. As part of the settlement, the Company agreed to withdraw its request to reconcile fuel costs for the period from July 1, 2009 through September 30, 2011 and submit a future fuel reconciliation request covering the period beginning July 1, 2009 and ending no later than June 30, 2013 by December 31, 2013 or as part of its next rate case, if earlier. The settlement also provides for the continuation of the energy efficiency cost recovery factor and the military base discount recovery factor. Both of these surcharges require annual filings to reconcile and revise the recovery factors. 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. The Company filed the following petition with the PUCT to refund fuel cost over-recoveries, due primarily to fluctuations in natural gas markets and consumption levels. The table summarizes the docket number assigned by the PUCT, the date the Company filed the petition and the date a final order was issued by the PUCT approving the refund to customers. The fuel cost over-recovery period represents the months in which the over-recoveries took place, and the refund period represents the billing month in which customers received the refund amounts shown, including interest: Docket No. Date Filed Date Approved 40622 August 3, 2012 September 28, 2012 Recovery Period January 2011- June 2012 11 Refund Period Refund Amount Authorized (In thousands) September 2012 $ 6,600 Table of Contents The Company filed the following petitions with the PUCT to revise its fixed fuel factor pursuant to the fuel factor formula authorized in PUCT Docket No. 37690: Docket No. Date Filed Date Approved Increase (Decrease) in Fuel Factor Effective Billing Month 40302 April 12, 2012 April 25, 2012 (18.5)% May 2012 41803 September 9, 2013 September 23, 2013 12.2% October 2013 Fuel Reconciliation Proceeding. On September 27, 2013, the Company filed an application with the PUCT, designated as Docket No. 41852, to reconcile $545.3 million of fuel and purchased power expenses incurred during the 45-month period from July 1, 2009 through March 31, 2013. The fuel reconciliation requests to recover $3.4 million of rewards for Palo Verde operations. Intervenor testimony is due February 28, 2014 and PUCT Staff testimony is due March 7, 2014. Hearings in the fuel reconciliation are scheduled to begin March 31, 2014 and a final order must be issued by September 26, 2014. Montana Power Station Approvals. The Company has received a Certificate of Convenience and Necessity ("CCN") authorization from the PUCT to construct the first two (of four) units of the MPS which are scheduled to come on line before the summer peak in 2015. The Company must also obtain air permits from state and federal regulatory agencies before it can begin construction. On January 22, 2014, the Texas Commission on Environmental Quality ("TCEQ") issued the required permit. The EPA issued a draft permit for GHG in September 2013 and solicited public comment. EPA is considering comments filed in response to that proposal before issuing a final permit. The Company believes that the type of facility planned at the MPS complies with all EPA regulations for granting a GHG permit and that the issues raised in the comments have previously been resolved in proceedings in other regions in favor of the grant of a permit. If the permit is granted, commenters may challenge the determination before the U.S. EPA’s Environmental Appeals Board. While the Company believes that this application demonstrates compliance with all applicable regulations, it cannot predict the timing or final outcome. On September 6, 2013, the Company filed an application with the PUCT for issuance of a CCN to construct, own and operate two additional 88 MW natural gas-fired generating units designated as the MPS Units 3 and 4 in El Paso County, Texas which are scheduled to come on line before the summer peak in 2016 and 2017. The case has been designated PUCT Docket No. 41763. Hearings in this case were held in February 2014. In accordance with PUCT rules, the final order must be issued by September 5, 2014. The Company filed three transmission line CCN applications with the PUCT as part of the MPS Project: • MPS to Caliente: a 115-kV transmission line from the MPS to the existing Caliente Substation in east El Paso. (PUCT Docket No. 41360) • MPS In & Out: a 115-kV transmission line from the MPS to intersect with the existing Caliente - Coyote 115-kV transmission line. (PUCT Docket No. 41359) • MPS to Montwood: a 115-kV transmission line from the MPS to the existing Montwood Substation in east El Paso. (PUCT Docket No. 41809) The transmission CCN filings for both the MPS to Caliente and the MPS In & Out were filed on April 15, 2013, and the transmission CCN filing for the MPS to Montwood was filed on September 24, 2013. The Company is requesting to build these transmission lines to connect the new MPS to the electrical grid in order to meet increased customer growth and electric demand and to improve system reliability. A final order approving a unanimous settlement in the MPS to Caliente transmission CCN filing is expected by the end of the first quarter of 2014. Final orders in the transmission CCN filings for the MPS In & Out and the MPS to Montwood filings are expected no later than October 2014. Other Required Approvals. The Company has obtained other required approvals for recovery of fuel costs through fixed fuel factors, other tariffs and approvals as required by the Public Utility Regulatory Act ( the "PURA") and the PUCT. 12 Table of Contents New Mexico Regulatory Matters 2009 New Mexico Stipulation. On December 10, 2009, the NMPRC issued a final order conditionally approving the stipulated rates in NMPRC Case No. 09-00171-UT. The stipulated rates went into effect with January 2010 bills. The stipulated rates provide for an Efficient Use of Energy Factor Rate Rider to recover energy efficiency expenditures which requires an annual filing and approval of the related incentives and adjustment to the recovery factors. Fuel and purchased power costs in New Mexico are recovered through a Fuel and Purchased Power Cost Recovery Factor (the "FPPCAC"). On January 8, 2014, the NMPRC approved the continuation of the FPPCAC without modification. The Company recovers its investment in Palo Verde Unit 3 in New Mexico through the FPPCAC as purchased power using a proxy market price approved in the 2009 New Mexico rate stipulation. 2013 Annual Procurement Plan Pursuant to the Renewable Energy Act. On July 1, 2013, the Company filed its application for approval of its 2013 Annual Procurement Plan pursuant to the New Mexico Renewable Energy Act. On November 20, 2013, the NMPRC issued a final order approving the renewable procurement plan with modifications recommended by the Hearing Examiner. The plan sets out the Company's procurement of renewable resources and estimated costs for 2014 and 2015 to meet Renewable Portfolio Standards ("RPS") and resource diversity requirements. The approved plan provides for the RPS and diversity requirements for 2014 and 2015 to be met with a combination of previously approved resources and grants the Company's request for waiver for meeting the full RPS through 2015 due to reasonable cost threshold limits. The order also grants the Company's requested diversity variances for 2014 and 2015. Costs for purchases of renewable energy delivered to the Company are recovered through the FPPCAC and purchases of unbundled renewable energy credits are recovered through base rates. Long-Term Purchased Power Agreement with Macho Springs. On November 21, 2012, the Company filed an application with the NMPRC requesting approval of a Long-Term Purchase Power Agreement (the "LTPPA") with Macho Springs Solar, LLC ("Macho Springs") to purchase energy from a 50 MW solar facility to be constructed by Macho Springs on the Company's New Mexico transmission system. The Company also sought approval of the recovery of costs associated with the LTPPA through the Company's FPPCAC. A final order approving the LTPPA and recovery through the FPPCAC was received May 1, 2013. Montana Power Station Approvals. The Company has received a CCN authorization from the NMPRC to construct the first two (of four) units of the MPS. As discussed above, the Company must also obtain air permits from the TCEQ and EPA before it can begin construction. On September 6, 2013, the Company filed an application with the NMPRC for issuance of a CCN to construct, own and operate two additional 88 MW natural gas-fired generating units designated as the MPS Units 3 and 4 in El Paso County, Texas. The case has been designated NMPRC Case No. 13-00297-UT. No protests to the Company's application were filed and the hearing examiner issued a recommended decision to approve the Company's application on February 20, 2014. A final order is expected in the first quarter of 2014. Revolving Credit Facility, Issuance of Long-Term Debt and Guarantee of Debt. On October 30, 2013, the Company received approval in NMPRC Case No. 13-00317-UT to amend its current $300 million RCF to include an option, subject to lender's approval, to expand the amount of the potential borrowings available under the facility to $400 million and extend the maturity date by up to four years ; issue up to $300 million in new long-term debt; and to guarantee the issuance of up to $50 million of new debt by RGRT to finance future purchases of nuclear fuel and to refinance existing debt obligations related to the financing of purchases of nuclear fuel. 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. Under the terms of the agreement, the Company has available $300 million and the ability to increase the RCF by up to $100 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 has a term ending January 2019. The Company may extend the maturity date up to two times, in each case for an additional one year period upon the satisfaction of certain conditions. Other Required Approvals. The Company has obtained other required approvals for other tariffs, securities transactions, long-term resource plans, recovery of energy efficiency costs through a base rate rider and other approvals as required by the NMPRC. 13 Table of Contents Federal Regulatory Matters Public Service Company of New Mexico's ("PNM") 2010 Transmission Rate Case. On October 27, 2010, PNM filed a Notice of Transmission Rate Change for transmission delivery services provided by PNM. These rates went into effect on June 1, 2011. The Company takes transmission service from PNM. On January 2, 2013, the FERC issued a letter order approving a unanimous stipulation and agreement. Pursuant to the stipulation, on January 31, 2013, PNM refunded $1.9 million for amounts that PNM collected since June 1, 2011 in excess of settlement rates. This amount was recorded in the fourth quarter of 2012 as a reduction of transmission expense. Revolving Credit Facility, Issuance of Long-Term Debt and Guarantee of Debt. On September 30, 2013, the Company filed an application for approval to amend its current $300 million RCF to include an option, subject to lender's approval, to expand the amount of the potential borrowings available under the facility to $400 million and extend the maturity date by up to four years; issue up to $300 million in new long-term debt; and to guarantee the issuance of up to $50 million of new debt by RGRT to finance future purchases of nuclear fuel and to refinance existing debt obligations related to the purchase of nuclear fuel. The FERC issued an order approving the filing on November 15, 2013. The case was assigned to FERC Docket No. ES 13-59-000. As noted above, on January 14, 2014, the Company and RGRT entered into a second amended and restated credit agreement related to the RCF. Other Required Approvals. The Company has obtained required approvals for rates and tariffs, securities transactions and other approvals as required by the FERC. Department of Energy ("DOE"). The DOE regulates the Company's exports of power to the Comision Federal de Electricidad in Mexico pursuant to a license granted by the DOE and a presidential permit. The DOE is authorized to assess operators of nuclear generating facilities a share of the costs of decommissioning the DOE's uranium enrichment facilities and for the ultimate costs of disposal of spent nuclear fuel. See Facilities-Palo Verde Station for discussion of spent fuel storage and disposal costs. Sales for Resale The Company provides firm capacity and associated energy to the RGEC pursuant to an ongoing contract with a two-year notice to terminate provision. The Company also provides network integrated transmission service to 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 2014. Franchises and Significant Customers El Paso and Las Cruces Franchises The Company has a franchise agreement with El Paso, the largest city it serves. The franchise agreement allows the Company to utilize public rights-of-way necessary to serve its retail customers within El Paso. The Company is also providing electric distribution service to Las Cruces under an implied franchise by satisfying all obligations under the franchise agreement that expired on April 30, 2009. The franchise arrangements held between the Company and the cities of El Paso and Las Cruces are detailed below: City El Paso Las Cruces Period August 1, 2010 - Present February 1, 2000 - Present Franchise Fee (a) (b) 4.00% 2.00% (a) Based on a percentage of revenue. (b) 0.75% of the El Paso franchise fee is to be placed in a restricted fund to be used solely for economic development and renewable energy purposes. 14 Table of Contents Military Installations The Company serves Holloman Air Force Base ("Holloman"), White Sands Missile Range ("White Sands") and Fort Bliss. The military installations represent approximately 5% of the Company's annual retail revenues. Fort Bliss takes retail electric service from the Company under the applicable Texas tariffs. The Company is serving White Sands under the applicable New Mexico tariffs. In March 2006, the Company signed a contract with Holloman that provides for the Company to provide retail electric service and limited wheeling services to Holloman for a ten-year term which expires in January 2016. 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 new guidance from the SEC, we may also use the Investor Relations section of our website (www.epelectric.com) to communicate with investors about our company. It is possible that the financial information we post there could be deemed to be material information. The information on our website is not part of this document. 15 Table of Contents The executive officers of the Company are elected annually and serve at the discretion of the Board of Directors. The executive officers of the Company as of February 26, 2014, were as follows: Executive Officers of the Registrant Name Thomas V. Shockley III David G. Carpenter ...... Hector R. Puente .......... Steven T. Buraczyk....... Age 68 Chief Executive Officer since May 2012; Interim Chief Executive Officer from January 2012 to May 2012; Non-Employee Member of the Board of Directors from May 2010 to January 2012; Vice – Chairman and Chief Operating Officer for American Electric Power from June 2000 to August 2004; retired in 2004. Current Position and Business Experience 58 Executive Vice President since October 2013; Senior Vice President and Chief Financial Officer from August 2009 to October 2013; Vice President – Regulatory Services and Controller from September 2008 to August 2009. 57 Executive Vice President since October 2013; Senior Vice President and Chief Operations Officer from June 2012 to October 2013; Senior Vice President – Operations from May 2011 to May 2012; Vice President – Transmission and Distribution from January 2006 to May 2011. 46 Senior Vice President – Operations since October 2013;Vice President of Regulatory Affairs from April 2013 to October 2013; Vice President of Power Marketing and Fuels and Resource and Delivery Planning from August 2012 to April 2013; Vice President – System Operations and Planning from January 2011 to August 2012; Vice President – Power Marketing and Fuels from July 2008 to January 2011. Nathan T. Hirschi ......... 50 Senior Vice President and Chief Financial Officer since October 2013;Vice President and Controller from March 2010 to October 2013; Vice President – Special Projects from December 2009 to February 2010; Partner for KPMG LLP from October 2003 to April 2009. Mary E. Kipp................ 46 Senior Vice President, General Counsel and Chief Compliance Officer since June 2010; Vice President – Legal and Chief Compliance Officer from December 2009 to June 2010; Assistant General Counsel and Director of FERC Compliance from December 2007 to December 2009. Rocky R. Miracle ......... 61 Senior Vice President – Corporate Planning and Development since August 2009; Vice President – Corporate Planning from September 2008 to August 2009. Item 1A. Risk Factors Like other companies in our industry, our financial results will be impacted by weather, the economy of our service territory, market prices for power, fuel prices, and the decisions of regulatory agencies. Our common stock price and creditworthiness will be affected by local, regional and national macroeconomic trends, general market conditions and the expectations of the investment community, all of which are largely beyond our control. In addition, the following statements highlight risk factors that may affect our financial condition and results of operations. These are not intended to be an exhaustive discussion of all such risks, and the statements below must be read together with factors discussed elsewhere in this document and in our other filings with the SEC. Our Revenues and Profitability Depend upon Regulated Rates Our retail rates are subject to regulation by incorporated municipalities in Texas, the PUCT, the NMPRC and the FERC. The settlement approved in the Company's 2012 Texas rate case, PUCT Docket No. 40094, established the Company's current retail base rates in Texas, effective May 1, 2012. In addition, the settlement in the Company's 2009 New Mexico rate case, NMPRC Case , established rates in New Mexico that became effective on January 2010. Our profitability depends on our ability to recover the costs, including a reasonable return on invested capital, of providing electric service to our customers through base rates approved by our regulators. These rates are generally established based on an analysis of the expenses we incur in a historical test year, and as a result, the rates ultimately approved by our regulators may or may not match our expenses at any given time and recovery of expenses may lag behind the occurrence of those expenses. Rates in New Mexico may be established using projected costs and investment for a future test year period in certain instances. While rate regulation is based on the assumption that we will have a reasonable opportunity to recover our costs and earn a reasonable rate of return on our invested capital, there can be no assurance that our future Texas rate cases or New Mexico rate cases will result in base rates that will allow us to fully recover our costs including a reasonable return on invested capital. There can be no assurance that regulators will determine that all of our costs are reasonable and have been prudently incurred including 16 Table of Contents costs associated with future plant retirement and asset retirement obligations. It is also likely that third parties will intervene in any rate cases and challenge whether our costs are reasonable and necessary. If all of our costs are not recovered through the retail base rates ultimately approved by our regulators, our profitability and cash flow could be adversely affected which, over time, could adversely affect our ability to meet our financial obligations. We May Not Be Able To Recover All Costs of New Generation During 2013, we completed the construction of Rio Grande Unit 9, an aeroderivative unit with a generating capacity of 87 MW, which reached commercial operation in May 2013. In addition, we have received approval from both the PUCT and the NMPRC of the CCN to construct the first two units of the Montana Power Station, a new plant site, which will initially consist of two 88 MW simple-cycle aeroderivative combustion turbines. We have risk related to recovering all costs associated with the construction of Rio Grande Unit 9 and other new units. In 2012, we issued $150 million in aggregate principal amount of 3.30% Senior Notes, due December 15, 2022. The 3.30% Senior Notes along with our revolving credit facility, which was amended and restated on January 14, 2014, could help fund the construction of the Montana Power Station and other new units. The costs of financing and constructing these units will be reviewed in future rate cases in both Texas and New Mexico. To the extent that the PUCT or 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 these units are not completed on time, we may be required to purchase power or operate less efficient generating units to meet customer requirements. Any replacement purchased power or fuel costs will be subject to regulatory review by the PUCT and the NMPRC. We face financial risks to the extent that recovery is not allowed for any replacement fuel costs resulting from delays in the completion of these new units or other new units. Weakness in the Economy and Uncertainty in the Financial Markets Could Reduce Our Sales, Hinder Our Capital Programs and Increase Our Funding Obligations for Pensions and Decommissioning In recent years, the global credit and equity markets and the overall economy have been through a state of turmoil. These and future events could have a number of effects on our operations and our capital programs. For example, tight credit and capital markets could make it difficult and more expensive to raise capital to fund our operations and capital programs. If we are unable to access the credit markets, we could be required to defer or eliminate important capital projects in the future. In addition, declines in the stock market performance may reduce the value of our financial assets and decommissioning trust investments. Such market results may also increase our funding obligations for our pension plans, other post-retirement benefit plans and nuclear decommissioning trusts. Changes in the corporate interest rates which we use as the discount rate to determine our pension and other post-retirement liabilities may have an impact on our funding obligations for such plans and trusts. Further, continued economic volatility may result in reduced customer demand, both in the retail and wholesale markets, and increases in customer delinquencies and write-offs. 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. This is not intended to be an exhaustive list of possible effects, and we may be adversely impacted in other ways. Our Costs Could Increase or We Could Experience Reduced Revenues if There are Problems at the Palo Verde Nuclear Generating Station A significant percentage of our generating capacity, off-system sales margins, assets and operating expenses is attributable to Palo Verde. Our 15.8% interest in each of the three Palo Verde units totals approximately 633 MW of generating capacity. Palo Verde represents approximately 34% of our available net generating capacity and provided approximately 46% of our energy requirements for the twelve months ended December 31, 2013. Palo Verde comprises approximately 29% 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 91.1% and 92.3% in the twelve months ended December 31, 2013 and 2012, respectively. Our ability to increase retail base rates in Texas and New Mexico is limited. We cannot assure that revenues will be sufficient to recover any increased costs, including any increased costs in connection with Palo Verde or other operations, whether as a result 17 Table of Contents of inflation, changes in tax laws, regulatory requirements, the costs of securing the facilities against possible terrorist attacks, or other causes. We May Not Be Able to Recover All of Our Fuel Expenses from Customers In general, by law, we are entitled to recover our reasonable and necessary fuel and purchased power expenses from our customers in Texas and New Mexico. NMPRC Case No. 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 New Mexico and Texas are subject to reconciliation by the PUCT and NMPRC. Prior to the completion of a reconciliation, we record fuel and purchased power costs such that fuel revenues equal recoverable fuel and purchased power expense including the repriced energy costs for Palo Verde Unit 3 in New Mexico. In September 2013, we filed an application with the PUCT (Docket No. 41852), to reconcile $545.3 million of fuel and purchased power expenses incurred during the 45-month period from July 2009 through March 31, 2013. In the event that recovery of fuel and purchased power expenses is denied in this or future reconciliation proceedings, the amounts recorded for fuel and purchased power expenses could differ from the amounts we are allowed to collect from our customers, and we would incur a loss to the extent of the disallowance. In New Mexico, the FPPCAC allows us to reflect current fuel and purchased power expenses in the FPPCAC and to adjust for under-recoveries and over-recoveries with a two-month lag. In Texas, fuel costs are recovered through a fixed fuel factor. In Texas, we can seek to revise our fixed fuel factor based upon our approved formula at least four months after our last revision except in the month of December. If we materially under-recover fuel costs, we may seek a surcharge to recover those costs at any time the balance exceeds a threshold material amount and is expected to continue to be materially under-recovered. During periods of significant increases in natural gas prices, the Company realizes a lag in the ability to reflect increases in fuel costs in its fuel recovery mechanisms in Texas. As a result, cash flow is impacted due to the lag in payment of fuel costs and collection of fuel costs from customers. To the extent the fuel and purchased power recovery processes in Texas and New Mexico do not provide for the timely recovery of such costs, we could experience a material negative impact on our cash flow. At December 31, 2013 and 2012, the Company had a net under-collection balance of $6.2 million and a net over-collection balance of $4.6 million, respectively. Equipment Failures and Other External Factors Can Adversely Affect Our Results The generation and transmission of electricity require the use of expensive and complex equipment. While we have a maintenance program in place, generating plants are subject to unplanned outages because of equipment failure and severe weather conditions. The advanced age of several of our gas-fired generating units in or near El Paso increases the vulnerability of these units. In the event of unplanned outages, we must acquire power from others at unpredictable costs in order to supply our customers and comply with our contractual agreements. This additional purchased power cost would be subject to review and approval of the PUCT and the NMPRC in reconciliation proceedings. As noted above, in the event that recovery for fuel and purchased power expenses could differ from the amounts we are allowed to collect from our customers, we would incur a loss to the extent of the disallowance. This can materially increase our costs and prevent us from selling excess power at wholesale, thus reducing our profits. In addition, actions of other utilities may adversely affect our ability to use transmission lines to deliver or import power, thus subjecting us to unexpected expenses or to the cost and uncertainty of public policy initiatives. Concerns over physical security of transmission lines is also increasing, which may require us to incur additional capital and operating costs. Damage to certain transmission 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 and Four Corners) is located hundreds of miles from El Paso and Las Cruces and must be delivered to our customers over long distance transmission lines. In addition, Palo Verde’s availability is an important factor in realizing off-system sales margins. These factors, as well as interest rates, economic conditions, fuel prices and price volatility, are largely beyond our control, but may have a material adverse effect on our earnings, cash flow and financial position. Competition and Deregulation Could Result in a Loss of Customers and Increased Costs As a result of changes in federal law, our wholesale and large retail customers already have access to, in varying degrees, alternative sources of power, including co-generation of electric power. Deregulation legislation is in effect in Texas requiring us to separate our transmission and distribution functions, which would remain regulated, from our power generation and energy services businesses, which would operate in a competitive market, in the future. In 2004, the PUCT approved a rule delaying retail competition in our Texas service territory. This rule was codified in the 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 they are achieved at all. There is substantial 18 Table of Contents uncertainty about both the regulatory framework and market conditions that would exist if and when retail competition is implemented in our Texas service territory, and we may incur substantial preparatory, restructuring and other costs that may not ultimately be recoverable. There can be no assurance that deregulation would not adversely affect our future operations, cash flow and financial condition. Future Costs of Compliance with Environmental Laws and Regulations Could Adversely Affect Our Operations and Financial Results We are or may become subject to extensive federal, state and local environmental statutes, rules and regulations relating to discharges into the air, air quality, discharges of effluents into water, water quality, the use of water, the handling, disposal and clean-up of hazardous and non-hazardous substances and wastes, natural resources, and health and safety. Compliance with these legal requirements, which change frequently and often become more restrictive, could require us to commit significant capital and operating resources toward permitting, emission fees, environmental monitoring, installation and operation of air quality control equipment and purchases of air emission allowances and/or offsets. These could also result in limitations in operating hours and/ or changes in construction schedules for future generating units. Costs of compliance with environmental laws and regulations or fines or penalties resulting from non-compliance, if not recovered in our rates, could adversely affect our operations and/or financial results, especially if emission and/or discharge limits are tightened, more extensive permitting requirements are imposed, additional substances become regulated and the number and types of assets we operate increases. We cannot estimate our compliance costs or any possible fines or penalties with certainty, or the degree to which such costs might be recovered in our rates, due to our inability to predict the requirements and timing of implementation of environmental rules or regulations. For example, the EPA has issued in the recent past various final and proposed regulations regarding air emissions from our operations as well as the rest of the utility sector, including the Cross-Sate Air Pollution Rule and the GHG New Source Performance Standard ("NSPS") for Electric Generating Units. If these regulations become finalized and survive legal challenges, the cost to us to comply could adversely affect our operations and our financial results. Compliance with environmental laws and regulations also adds uncertainty to the timing and costs of our future generation additions. We filed separate air permit applications for the MPS, our proposed new generation facility in far east El Paso, with the TCEQ and the EPA in April 2012. TCEQ issued a final permit on January 22, 2014, following a contested case process. The application filed with the EPA yielded a draft permit in September 2013, a public hearing on October 24, 2013, and a public comment period that ended December 4, 2013. While a final permit from the EPA regional office is expected in a few months, this process could be extended if an Environmental Appeals Board review is requested. While we believe that this application demonstrates compliance with all applicable regulations, we cannot predict the timing or final outcome. Climate Change and Related Legislation and Regulatory Initiatives Could Affect Demand for Electricity or Availability of Resources, and Could Result in Increased Compliance Costs The Company emits GHGs through the operation of its power plants. Federal legislation had been introduced in both houses of Congress to regulate the emission of GHGs and numerous states have adopted programs to stabilize or reduce GHG emissions. Additionally, the EPA is proceeding with regulation of GHG under the CAA. Under EPA regulations finalized in May 2010, the EPA began requiring permits for GHG emissions from certain stationary sources, including most power plants, in January 2011. The U.S. Supreme Court held oral argument on February 24, 2014, regarding the legality of these permitting requirements. Regardless of the outcome, the EPA plans to exercise other EPA GHG rulemaking authority. For example, on January 8, 2014, the EPA published a proposal to establish new source performance standards limiting GHG emission from electric generating units on which construction commences after that date. The EPA is also in the early stages of developing NSPS for existing sources based on its eventual adoption of NSPS for new sources. The potential impact of these rules (if finalized) on the Company is unknown at this time, but they could result in significant costs, limitations on operating hours, and/or changes in construction schedules for future generating units. It is not currently possible to predict how any pending, proposed or future GHG legislation by Congress, the states or multi- state regions or any such regulations adopted by the EPA or state environmental agencies will impact our business. However, any legislation or regulation of GHG emissions or any future related litigation could result in increased compliance costs or additional operating restrictions or increased or reduced demand for our services, could require us to purchase rights to emit GHG, and could have a material adverse effect on our business, financial condition, reputation or results of operations. 19 Table of Contents 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, 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 information; and could result in legal claims or proceedings, liability or regulatory penalties against us, damage our reputation or otherwise harm our business. Additionally, we cannot predict the impact that any future information technology or terrorist attack may have on the energy industry in general. The effects of such attacks against us or others in the energy industry could increase the cost of regulatory compliance, increase the cost of insurance coverage or result in a decline in the U.S. economy which could negatively affect our results of operations and financial condition. Ongoing and future governmental efforts to regulate cybersecurity in the energy industry could lead to increased regulatory compliance costs, require us to make capital expenditures or otherwise harm our business. 20 Table of Contents 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 private rights-of-ways, easements, or on streets or highways by public consent. The Company owns an executive and administrative office building in El Paso. The Company leases land in El Paso adjacent to the Newman Power Station under a lease which expires in June 2033 with a renewal option of 25 years. The Company also leases certain warehouse facilities in El Paso under a lease which expires in December 2015. The Company has several other leases for office and parking facilities which expire within the next four years. Item 3. Legal Proceedings The Company is a party to various legal actions. In many of these matters, the Company has excess casualty liability insurance that covers the various claims, actions and complaints. Based upon a review of these claims and applicable insurance coverage, the Company believes that none of these claims will have a material adverse effect on the financial position, results of operations or cash flows of the Company. See "Environmental Matters" and "Regulation" for discussion of the effects of government legislation and regulation on the Company. Item 4. Mine Safety Disclosures Not Applicable. 21 Table of Contents 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: 2012 First Quarter ............... $ Second Quarter ........... Third Quarter.............. Fourth Quarter ............ 2013 First Quarter ............... $ Second Quarter ........... Third Quarter.............. Fourth Quarter ............ Sales Price High Low Close Dividends (End of period) $ $ 35.34 33.65 34.93 35.01 34.18 38.91 39.12 36.18 $ $ 31.58 29.17 32.45 30.15 31.84 32.47 32.26 32.43 32.49 33.16 34.25 31.91 33.65 35.31 33.40 35.11 $ $ 0.22 0.25 0.25 0.25 0.25 0.265 0.265 0.265 22 Table of Contents 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, 2008 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 12/31/2008 100 100 100 12/31/2009 112 111 125 12/31/2010 152 119 138 12/31/2011 194 142 130 12/31/2012 184 145 147 12/31/2013 209 164 181 As of January 31, 2014, there were 2,677 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 $42.0 million in cash dividends during the twelve months ended December 31, 2013. On January 23, 2014, the Board of Directors declared a quarterly cash dividend of $0.265 per share payable on March 31, 2014 to shareholders of record on March 14, 2014. The Board of Directors plans to review the Company's dividend policy annually in the second quarter of each year. We are currently targeting a payout ratio of approximately 45%. Declaration and payment of dividends is subject to compliance with certain financial ratios under Texas law. Since 1999, the Company has also returned cash to stockholders through a stock repurchase program pursuant to which the Company has bought approximately 25.4 million shares at an aggregate cost of $423.6 million, including commissions. Under the Company’s program, purchases can be made at open market prices or in private transactions and repurchased shares are available for issuance under employee benefit and stock incentive plans, or may be retired. On March 21, 2011, the Board of Directors authorized a repurchase of up to 2.5 million shares of the Company’s outstanding common stock (the "2011 Plan"). No shares of common stock were repurchased during the twelve months ended December 31, 2013 under the 2011 Plan. The table below provides the amount of the fourth quarter issuer purchases of equity securities. Period Total Number of Shares Purchased (a) October 1 to October 31, 2013 November 1 to November 30, 2013 December 1 to December 31, 2013 _____________________ (a) Represents shares of common stock delivered to us as payment of withholding taxes due upon the vesting of — $ — 4,930 — — — Total Number of Shares Purchased as Part of a Publicly Announced Program Average Price Paid per Share (Including Commissions) — — 35.11 Maximum Number of Shares that May Yet Be Purchased Under the Plans or Programs 393,816 393,816 393,816 restricted stock held by our employees, not considered part of the 2011 Plan. 23 Table of Contents For Equity Compensation Plan Information see Part III, Item 12 – Security Ownership of Certain Beneficial Owners and Management. 24 Table of Contents Item 6. Selected Financial Data As of and for the following periods (in thousands except for share and per share data): Operating revenues ........................................................ $ Operating income........................................................... Income before extraordinary items ................................ $ Extraordinary gain, net of tax (a)................................... $ Net income ..................................................................... $ Basic earnings per share: Income before extraordinary items......................... $ Extraordinary gain (a)............................................. $ Net income....................................................... $ 2.20 Weighted average number of shares outstanding........... 40,114,594 Diluted earnings per share: 2.20 — $ $ Years Ended December 31, 2013 890,362 165,635 88,583 2012 852,881 168,658 90,846 $ $ $ 2011 918,013 190,803 103,539 $ $ $ $ $ $ — $ — $ — $ 88,583 $ $ 90,846 2.27 $ $ 103,539 2.49 $ $ — $ 2.27 $ — $ 2.49 $ 2010 877,251 168,962 90,317 10,286 100,603 2.08 0.24 2.32 2009 827,996 133,165 66,933 — 66,933 1.50 — 1.50 $ $ $ $ $ $ $ $ 39,974,022 41,349,883 43,129,735 44,524,146 Income before extraordinary items......................... $ Extraordinary gain (a)............................................. $ Net income....................................................... $ 2.20 $ — $ 2.20 $ 2.26 $ — $ 2.26 $ 2.48 $ — $ 2.48 $ 2.07 0.24 2.31 $ $ $ 1.50 — 1.50 Weighted average number of shares and dilutive potential shares outstanding................................... 40,126,647 40,055,581 41,587,059 43,294,419 44,595,067 Dividends declared per share of common stock ............ $ Cash additions to utility property, plant and equipment $ 237,411 Total assets..................................................................... $ 2,786,288 Long-term debt and financing obligations, net of 1.045 $ $ 0.97 202,387 $ $ 0.66 178,041 $ $ — $ — 169,966 $ 209,974 $ 2,669,050 $ 2,396,851 $ 2,364,766 $ 2,226,152 current portion ....................................................... $ Common stock equity .................................................... $ 999,620 943,833 $ $ 999,535 824,999 $ $ 816,497 760,251 $ $ 849,745 810,375 $ $ 804,975 722,729 ______________________ (a) Extraordinary gain for 2010 represents a $10.3 million extraordinary gain or $0.24 earnings per share related to Texas regulatory assets. 25 Table of Contents Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations As you read this Management’s Discussion and Analysis, please refer to our 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 Generally Accepted Accounting Principles ("GAAP"). Note A to the financial statements contains a summary of our significant accounting policies, many of which require the use of estimates and assumptions. We believe that of our significant accounting policies, the following are noteworthy because they are based on estimates and assumptions that require complex, subjective assumptions by management, which can materially impact reported results. Changes in these estimates or assumptions, or actual results that are different, could materially impact our financial condition and results of operation. Regulatory Accounting We apply accounting standards that recognize the economic effects of rate regulation in our Texas, New Mexico and FERC jurisdictions. As a result, we record certain costs or obligations as either assets or liabilities on our balance sheet and amortize them in subsequent periods as they are reflected in regulated rates. The deferral of costs as regulatory assets is appropriate only when the future recovery of such costs is probable. In assessing probability, we consider such factors as specific regulatory orders, regulatory precedent and the current regulatory environment. As of December 31, 2013, we had recorded regulatory assets currently subject to recovery in future rates of approximately $101.1 million and regulatory liabilities of approximately $26.4 million as discussed in greater detail in Note D of the Notes to the Financial Statements. In the event we determine that we can no longer apply the FASB guidance for regulated operations to all or a portion of our operations or to the individual regulatory assets recorded, we could be required to record a charge against income in the amount of the remaining unamortized net regulatory assets. Such an action could materially reduce our shareholders' equity. Collection of Fuel Expense In general, by law and regulation, our actual fuel and purchased power expenses are recovered from our customers. In times of rising fuel prices, we experience a lag in recovery of higher fuel costs. These costs are subject to reconciliation by the PUCT and the NMPRC. Prior to the completion of a reconciliation proceeding, we record fuel transactions such that fuel revenues, including fuel costs recovered through base rates in New Mexico, equal fuel expense. In the event that a disallowance of fuel cost recovery occurs during a reconciliation proceeding, the amounts recorded for fuel and purchased power expenses could differ from the amounts we are allowed to collect from our customers, and we could incur a loss to the extent of the disallowance. Decommissioning Costs and Estimated Asset Retirement Obligation Pursuant to the ANPP Participation Agreement and federal law, we must fund our share of the estimated costs to decommission Palo Verde Units 1, 2, 3 and associated common areas. The determination of the estimated liability requires the use of various assumptions pertaining to decommissioning costs, escalation and discount rates. We determine how we will fund our share of those estimated costs by making assumptions about future investment returns and future decommissioning cost escalations. Decommissioning costs will be adjusted prospectively for future changes in estimated decommissioning costs and when actual costs are incurred to decommission the plant. If the rates of return earned by the trusts fail to meet expectations or if estimated costs to decommission the plant increase, we could be required to increase our funding to the decommissioning trust accounts. Historically, we have been permitted to collect in rates in Texas and New Mexico the costs of nuclear decommissioning. Future Pension and Other Postretirement Obligations Our obligations to retirees under various benefit plans are recorded as a liability on the balance sheets. Our liability is calculated on the basis of significant assumptions regarding discount rates, expected return on plan assets, rate of compensation increase, life expectancy of retirees and health care cost inflation. Changes in these assumptions could have a material impact on both net income and on the amount of liabilities reflected on the balance sheets. Tax Accruals We use the asset and liability method of accounting for income taxes. Under this method, we recognize deferred tax assets and liabilities for the future tax consequences attributable to temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities. The application of income tax law and regulations is complex and we 26 Table of Contents must make judgments regarding income tax exposures. Changes in these judgments, due to changes in law, regulation, interpretation, or audit adjustments can materially affect amounts we recognize in our financial statements. The following is an overview of our results of operations for the years ended December 31, 2013, 2012 and 2011. Net income for the years ended December 31, 2013, 2012 and 2011 is shown below: Overview Net income (in thousands) .................................................................................... $ Basic earnings per share........................................................................................ $ 88,583 2.20 $ 90,846 2.27 Years Ended December 31, 2013 2012 2011 103,539 2.49 27 Table of Contents The following table and accompanying explanations show the primary factors affecting the after-tax change in income before extraordinary item between the calendar years ended 2013 and 2012, 2012 and 2011, and 2011 and 2010 (in thousands): Prior year December 31 income before extraordinary item ......... $ Change in (net of tax): .................................................................. Increased interest on long-term debt (net of capitalized interest). Increased (decreased) retail non-fuel base revenues .................... Increased administrative and general expense.............................. Income tax benefit ........................................................................ Decreased (increased) customer care expense.............................. Increased (decreased) deregulated Palo Verde Unit 3 revenues... Increased (decreased) AFUDC ..................................................... Decreased (increased) operations and maintenance at fossil fuel generating plants........................................................................... Increased (decreased) off-system sales margins retained............. Increased (decreased) transmission wheeling revenue ................. Other ............................................................................................. Current year December 31 net income ......................................... $ 2013 90,846 $ 2012 103,539 2011 $ 90,317 (2,651) (a) (2,497) (b) (2,042) (e) 1,200 (g) 1,104 (i) 1,039 (k) (252) (6,385) (c) (5,730) (f) — 2,192 (i) (3,282) (l) (377) 21,198 (d) (1,342) 4,787 (h) (2,069) (j) (808) 900 (m) 1,745 (m) (3,804) (n) 763 298 137 (514) 88,583 (1,532) 1,095 (1,785) 1,241 (3,725) (o) (3,935) (p) 3,197 (q) 100 $ 90,846 $ 103,539 ______________________ (a) (b) (c) (d) (e) (f) (g) (h) (i) (j) (k) (l) Interest on long-term debt increased in 2013 compared to 2012 primarily due to interest on $150 million of 3.3% senior notes issued in December 2012 partially offset by the refunding and remarketing of two series of pollution control bonds at lower rates in August 2012. Retail non-fuel base revenues decreased in 2013 compared to 2012 primarily due to a decrease in non-fuel base revenues from sales to small commercial and industrial customers and large commercial and industrial customers reflecting the reduction in non-fuel base rates in Texas effective on May 1, 2012, and a 1.1% decrease in retail non-fuel base revenues from sales to pubic authorities. Retail non-fuel base revenues exclude fuel recovered through New Mexico base rates. Retail non-fuel base revenues decreased in 2012 compared to 2011 primarily due to a decrease in non-fuel base revenues from sales to small commercial and industrial customers and large commercial and industrial customer due to a reduction in non-fuel base rates in Texas effective May 1, 2012, increased use of lower interruptible rates and decreased consumption by several large commercial and industrial customers. Retail non-fuel base revenues increased in 2011 compared to 2010 primarily due to a 3.1% increase in kWh sales to retail customers reflecting hotter summer weather with higher non-fuel base summer rates and 1.4% growth in the average number of retail customers served in 2011. Administrative and general expenses increased in 2013 compared to 2012 primarily due to increased outside services related to software systems support and improvements and increased consulting and legal services related to the analysis of our future involvement at the Four Corners Generating Station. Administrative and general expenses increased in 2012 compared to 2011 primarily due to increased pension and benefits expense as a result of changes in actuarial assumptions used to calculate expenses for our retiree benefit plans. Income tax benefit of $2.7 million recorded in 2013 related to positive developments related to state income tax audits and settlements partially offset by a $1.5 million tax benefit recorded in the same period last year. A one-time charge to income tax expense was incurred in 2010 to recognize a change in tax law enacted in the Patient Protection and Affordable Care Act to eliminate the tax benefit related to the Medicare Part D subsidies with no comparable tax expense in 2011. Customer care expense decreased in 2013 compared to 2012 and 2012 compared to 2011 primarily due to a decrease in the provision for uncollectible accounts reflecting improved collection efforts. Customer care expense increased in 2011 compared to 2010 primarily due to increased costs for customer-related activities, an increase in uncollectible customer accounts, and an increase in payroll costs. Deregulated Palo Verde Unit 3 revenues in 2013 increased compared to 2012 due to a 19.2% increase in power prices partially offset by an 8.5% increase in the costs of nuclear fuel and a 3.8% decrease in generation. Deregulated Palo Verde Unit 3 revenues in 2012 reflect lower proxy market prices associated with the decline in natural gas prices and lower sales of the deregulated portion of Palo Verde Unit 3 to retail customers due mostly to its planned refueling outage in March and April 2012, and also reflect an increase in the costs of nuclear fuel. 28 Table of Contents (m) (n) (o) (p) (q) AFUDC (allowance for funds used during construction) increased primarily due to higher balances of construction work in progress subject to AFUDC primarily reflecting construction of Rio Grande Unit 9 placed in service in May 2013. AFUDC decreased in 2011 compared to 2010 primarily due to lower balances of construction work in progress subject to AFUDC reflecting the completion and placing in service the Newman Unit 5 Phase II generating plant in April 2011. Operations and maintenance at gas-fired fuel generating stations increased in 2011 compared to 2010 largely as a result of weather-related damage during severe winter weather in February 2011 and freeze protection upgrades. Off-system sales margins decreased in 2011 compared to 2010 primarily due to lower average market prices for power and an increase in sharing of off-system sales margins with customers from 25% to 90% effective in July 2010. Transmission revenues increased in 2011 compared to 2010 primarily due to a settlement agreement with Tucson Electric Power Company resolving a transmission dispute that resulted in a one-time adjustment to income of $3.9 million, pre- tax and annual revenue of $1.1 million per year. 29 Table of Contents Historical Results of Operations The following discussion includes detailed descriptions of factors affecting individual line items in the results of operations. The amounts presented below are presented on a pre-tax basis. Operating revenues We realize revenue from the sale of electricity to retail customers at regulated rates and the sale of energy in the wholesale power market generally at market-based prices. Sales for resale (which are FERC-regulated cost-based wholesale sales within our service territory) accounted for less than 1% of revenues in each of 2013, 2012 and 2011. Revenues from the sale of electricity include fuel costs that are recovered from our customers through fuel adjustment mechanisms. A significant portion of fuel costs are also recovered through base rates in New Mexico. We record deferred fuel revenues for the difference between actual fuel costs and recoverable fuel revenues until such amounts are collected from or refunded to customers. "Non-fuel base revenues" refers to our revenues from the sale of electricity excluding such fuel costs. Retail non-fuel base revenue percentages by customer class are presented below: Years Ended December 31, 2013 2012 2011 Residential............................................................................. Commercial and industrial, small ......................................... Commercial and industrial, large .......................................... Sales to public authorities ..................................................... Total retail non-fuel base revenues ................................ 43% 33 7 17 100% 42% 34 7 17 100% 41% 34 8 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 75% or more of our non-fuel base revenues. While this customer base is more stable, it is also more sensitive to changes in weather conditions. The current rate structure in New Mexico and Texas reflects higher base rates during the peak summer season of May through October and lower base rates during November through April for our residential and small commercial and industrial customers. As a result, our business is seasonal, with higher kWh sales and revenues during the summer cooling season. The following table sets forth the percentage of our retail non-fuel base revenues derived during each quarter for the periods presented: Years Ended December 31, 2013 2012 2011 January 1 to March 31.......................................... April 1 to June 30................................................. July 1 to September 30......................................... October 1 to December 31 ................................... Total.............................................................. 20% 27 33 20 100% 19% 27 33 21 100% 18% 27 34 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 2013, 2012 and 2011. Heating degree days ...................................... Cooling degree days ...................................... 2,426 2,695 2,009 2,876 2,402 3,135 2013 2012 2011 10-year Average 2,247 2,633 Cooling degree days decreased 6.3% for the twelve months ended December 31, 2013 when compared to the same period in 2012 and 14.0% for the twelve months ended December 31, 2013 when compared to the same period in 2011. Total cooling degree days in 2013 were at its lowest level since 2008. 30 Table of Contents Customer growth is a key driver in the growth of retail sales. The average number of retail customers grew 1.3% in 2013 and 1.8% in 2012. See the tables presented on pages 33 and 34 which provide detail on the average number of retail customers and the related revenues and kWh sales. Retail non-fuel base revenues. The rate structure effective July 1, 2010 through April 30, 2012 in Texas was based on the final order in PUCT Docket No. 37690. On April 17, 2012, the El Paso City Council (the "Council") approved the settlement of our 2012 Texas retail rate case and fuel reconciliation in PUCT Docket No. 40094 and on April 26, 2012, the administrative law judge issued an order implementing the settlement rates as temporary rates effective May 1, 2012. The PUCT approved the settlement on May 18, 2012. Under the terms of the settlement, among other things, we agreed to a reduction in our non-fuel base rates of $15 million annually, with the decrease being allocated primarily to Texas retail commercial and industrial customer classes. Retail non-fuel base revenues decreased by $3.8 million, or 0.7% for the twelve months ended December 31, 2013 when compared to the same period in 2012. The decrease in retail non-fuel base revenues was primarily due to decreased revenues from our commercial and industrial customers which reflect the impact of the reduction in non-fuel base rates for our Texas customers which became effective May 1, 2012. Non-fuel base revenues from sales to small commercial and industrial and large commercial and industrial customers decreased 1.8% and 4.3%, respectively. Retail non-fuel base revenues from sales to public authorities decreased 1.1%. While the kWh sales to public authorities increased by 0.3% in 2013 compared to 2012, revenues from this customer class reflect the impacts of recently installed solar photovoltaic generation at Fort Bliss and White Sands Missile Range. Additionally, 2013 revenues were negatively impacted by the federal government sequestration and shutdown in October 2013. KWh sales to small commercial and industrial customers decreased 0.7%. The decrease in retail non-fuel base revenues was partially offset by an increase of 1.1% in non-fuel base revenues from sales to residential customers reflecting a 1.2% increase in kWh sales to our residential customer class. The increase in kWh sales to our residential customers reflects a 1.3% increase in the average number of residential customers served. We experienced less favorable weather during our summer cooling season. Cooling degree days decreased 6.3% when compared to the same period in 2012 but were higher than the 10-year average by 2.4%. Heating degree days increased 20.8% over 2012 and were 8.0% higher than the 10-year average. Retail non-fuel base revenues decreased by $9.7 million or 1.7% for the twelve months ended December 31, 2012 when compared to the same period in 2011. Non-fuel base revenues from sales to small commercial and industrial customers and large commercial and industrial customers decreased 4.1% and 7.4%, respectively, which reflect the impact of the reduction in non- fuel base rates for our Texas customers which became effective May 1, 2012. In addition, increased use of lower interruptible rates and decreased consumption by several large commercial and industrial customers contributed to the decrease in non-fuel base revenues. KWh sales to large commercial and industrial customer decreased 1.2%. KWh sales to small commercial and industrial customers increased 0.6% primarily due to the 1.6% increase in the average number of customers served. KWh sales to residential customers increased 0.6% due to the 1.8% increase in the average number of customers served despite milder weather in 2012 compared to 2011. KWh sales to public authorities increased 2.4% and non-fuel base revenues from public authorities increased 1.9% compared to 2011. Fuel revenues. Fuel revenues consist of: (i) revenues collected from customers under fuel recovery mechanisms approved by the state commissions and the FERC, (ii) deferred fuel revenues which are comprised of the difference between fuel costs and fuel revenues collected from customers and (iii) fuel costs recovered in base rates in New Mexico. In New Mexico and with our sales for resale customer, the fuel adjustment clause allows us to recover under-recoveries or refund over-recoveries of current fuel costs above the amount recovered in base rates with a two-month lag. In Texas, fuel costs are recovered through a fixed fuel factor. We can seek to revise our fixed fuel factor based upon our approved formula at least four months after our last revision except in the month of December. In addition, if we materially over-recover fuel costs, we must seek to refund the over-recovery, and if we materially under-recover fuel costs, we may seek a surcharge to recover those costs. Fuel over and under recoveries are considered material when they exceed 4% of the previous twelve months' fuel costs. We under-recovered fuel costs by $10.8 million in the twelve months ended December 31, 2013. We over-recovered fuel costs by $18.5 million in the twelve months ended December 31, 2012 and we under-recovered fuel costs by $13.9 million in the twelve months ended December 31, 2011. Refunds of $6.9 million and $12.0 million were returned to our Texas customers in the twelve months ended December 31, 2012 and 2011, respectively. At December 31, 2013, we had a net fuel under-recovery balance of $6.2 million, including an under-recovery balance of $7.2 million in Texas and an over-recovery balance of $1.0 million in New Mexico. Over-recoveries in New Mexico will be refunded through our fuel adjustment clause during 2014. Off-system sales. Off-system sales are wholesale sales into markets outside our service territory. Off-system sales are primarily made in off-peak periods when we have competitive generation capacity available after meeting our regulated service obligations. We share 90% of off-system sales margins with our Texas and New Mexico customers, and we retain 10% of off-system sales margins. We are sharing 25% of our off-system sales margins with our sales for resale customer under the terms of a contract. 31 Table of Contents Typically, we realize a significant portion of our off-system sales margins in the first quarter of each calendar year when our native load is lower than at other times of the year, allowing for the sale in the wholesale market of relatively larger amounts of off-system energy generated from lower cost generating resources. Palo Verde's availability is an important factor in realizing these off-system sales margins. The table below shows MWhs, sales revenue, fuel costs, total margins, and retained margins made on off-system sales for the twelve months ended December 31, 2013, 2012 and 2011 (in thousands except for MWhs). MWh sales ..................................... Sales revenues ............................... $ Fuel cost......................................... $ Total margins................................. $ Retained margins ........................... $ Years Ended December 31, 2013 2,472,622 82,806 68,241 14,565 1,549 2012 2,614,132 72,770 62,481 10,289 1,098 $ $ $ $ 2011 2,687,631 78,059 74,736 3,323 (560) $ $ $ $ Off-system sales revenues increased $10.0 million or 13.8% for the twelve months ended December 31, 2013 when compared to the same period in 2012 as a result of higher average market prices for power partially offset by a 5.4% decline in MWh sales. Off-system sales revenues decreased $5.3 million or 6.8% for the twelve months ended December 31, 2012 when compared to 2011 as a result of lower average market prices for power and a 2.7% decline in MWh sales. For the twelve months ended December 31, 2013, retained margins increased $0.5 million when compared to the same period in 2012. For the twelve months ended December 31, 2012, retained margins increased $1.7 million when compared to the same period in 2011 primarily due to the negative impacts in 2011 of power purchases required for system reliability when key generation and transmission facilities were either out of service or were threatened to be out of service. 32 Table of Contents Comparisons of kWh sales and operating revenues are shown below: Years Ended December 31: kWh sales (in thousands): Retail: 2013 2012 Amount Percent Increase (Decrease) Residential............................................................. Commercial and industrial, small ......................... Commercial and industrial, large .......................... Sales to public authorities ..................................... Total retail sales........................................... 2,679,262 2,349,148 1,095,379 1,622,607 7,746,396 2,648,348 2,366,541 1,082,973 1,617,606 7,715,468 Wholesale: Sales for resale ...................................................... Off-system sales .................................................... Total wholesale sales................................... Total kWh sales .................................... 61,232 2,472,622 2,533,854 10,280,250 64,266 2,614,132 2,678,398 10,393,866 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 (1) . Under (over) collection of fuel.............................. New Mexico fuel in base rates .............................. Total fuel revenues (2).......................... Off-system sales: Fuel cost ................................................................ Shared margins...................................................... Retained margins................................................... Total off-system sales........................... $ 236,651 184,568 40,235 95,044 556,498 2,172 558,670 133,481 10,849 73,295 217,625 68,241 13,016 1,549 82,806 $ 234,095 188,014 42,041 96,132 560,282 2,318 562,600 130,193 (18,539) 74,154 185,808 62,481 9,191 1,098 72,770 Other (3) ....................................................................... Total operating revenues ...................... $ 31,261 890,362 $ 31,703 852,881 $ Average number of retail customers (4): Residential.................................................................... Commercial and industrial, small................................. Commercial and industrial, large ................................. Sales to public authorities ............................................ Total...................................................... 347,891 38,836 50 4,997 391,774 343,409 38,601 50 4,828 386,888 30,914 (17,393) 12,406 5,001 30,928 (3,034) (141,510) (144,544) (113,616) 2,556 (3,446) (1,806) (1,088) (3,784) (146) (3,930) 3,288 29,388 (859) 31,817 5,760 3,825 451 10,036 (442) 37,481 4,482 235 — 169 4,886 1.2% (0.7) 1.1 0.3 0.4 (4.7) (5.4) (5.4) (1.1) 1.1% (1.8) (4.3) (1.1) (0.7) (6.3) (0.7) 2.5 — (1.2) 17.1 9.2 41.6 41.1 13.8 (1.4) 4.4 1.3% 0.6 — 3.5 1.3 ___________________________ (1) (2) (3) (4) Excludes $6.9 million of refunds in 2012 related to prior periods' Texas deferred fuel revenues. Includes deregulated Palo Verde Unit 3 revenues for the New Mexico jurisdiction of $11.4 million and $9.8 million in 2013 and 2012, respectively. Represents revenues with no related kWh sales. The number of retail customers presented are based on the number of service locations. Previous presentations of the number of retail customers in 2012 were based on the number of bills rendered including consolidated bills for customers operating multiple facilities. Management believes the number of service locations provides a more accurate indicator of customers served than the number of bills rendered. 33 Table of Contents Years Ended December 31: kWh sales (in thousands): Retail: 2012 2011 Amount Percent Increase (Decrease) Residential ........................................................... Commercial and industrial, small........................ Commercial and industrial, large......................... Sales to public authorities.................................... Total retail sales ......................................... 2,648,348 2,366,541 1,082,973 1,617,606 7,715,468 2,633,390 2,352,218 1,096,040 1,579,565 7,661,213 Wholesale: Sales for resale..................................................... Off-system sales .................................................. Total wholesale sales.................................. Total kWh sales................................... 64,266 2,614,132 2,678,398 10,393,866 62,656 2,687,631 2,750,287 10,411,500 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 (1) Under (over) collection of fuel ............................ New Mexico fuel in base rates ............................ Total fuel revenues (2)........................ Off-system sales: Fuel cost............................................................... Shared margins .................................................... Retained margins ................................................. Total off-system sales ......................... $ 234,095 188,014 42,041 96,132 560,282 2,318 562,600 130,193 (18,539) 74,154 185,808 62,481 9,191 1,098 72,770 $ 234,086 196,093 45,407 94,370 569,956 2,122 572,078 145,130 13,917 73,454 232,501 74,736 3,883 (560) 78,059 Other (3)...................................................................... Total operating revenues..................... $ 31,703 852,881 $ 35,375 918,013 $ Average number of retail customers (4): Residential .................................................................. Commercial and industrial, small ............................... Commercial and industrial, large................................ Sales to public authorities........................................... Total.................................................... 343,409 38,601 50 4,828 386,888 337,440 37,978 50 4,693 380,161 14,958 14,323 (13,067) 38,041 54,255 1,610 (73,499) (71,889) (17,634) 9 (8,079) (3,366) 1,762 (9,674) 196 (9,478) (14,937) (32,456) 700 (46,693) (12,255) 5,308 1,658 (5,289) (3,672) (65,132) 5,969 623 — 135 6,727 0.6 % 0.6 (1.2) 2.4 0.7 2.6 (2.7) (2.6) (0.2) — (4.1)% (7.4) 1.9 (1.7) 9.2 (1.7) (10.3) — 1.0 (20.1) (16.4) — — (6.8) (10.4) (7.1) 1.8 % 1.6 — 2.9 1.8 _______________________ (1) (2) (3) (4) Excludes $6.9 million and $12.0 million of refunds in 2012 and 2011, respectively, related to prior periods' Texas deferred fuel revenues. Includes deregulated Palo Verde Unit 3 revenues for the New Mexico jurisdiction of $9.8 million and $14.8 million in 2012 and 2011, respectively. Represents revenues with no related kWh sales. 2011 includes a one-time $3.9 million settlement of a transmission dispute with Tucson Electric Power Company. The number of retail customers presented are based on the number of service locations. Previous presentations of the number of retail customers in 2012 were based on the number of bills rendered including consolidated bills for customers operating multiple facilities. Management believes the number of service locations provides a more accurate indicator of customers served than the number of bills rendered. 34 Table of Contents Energy expenses Our sources of energy include electricity generated from our nuclear, natural gas and coal generating plants and purchased power. Palo Verde represents approximately 34% of our available net generating capacity and approximately 53% of our Company- generated energy for the twelve months ended December 31, 2013. Fluctuations in the price of natural gas, which also is the primary factor influencing the price of purchased power, have had a significant impact on our cost of energy. Energy expenses increased $37.8 million or 15% for the twelve months ended December 31, 2013 compared to 2012, primarily due to (i) an increase of $36.3 million in natural gas costs due to a 24% increase in the average costs of gas, and (ii) increased costs of purchased power of $2.1 million resulting from an 18.3% increase in the average price of power purchased partially offset by a 12.5% decrease in MWh purchased. Energy expenses decreased $47.3 million or 15.9% for the twelve months ended December 31, 2012 compared to 2011, primarily due to (i) a decrease of $36.4 million in natural gas costs due to a 28% decrease in the average costs of gas partially offset by a 6% increase in MWh generated with natural gas, and (ii) decreased costs of purchased power of $14.9 million resulting from a 17% decrease in MWh purchased and a 3% decrease in the average price of power purchased. This decrease was partially offset by an increase of $5.7 million in the cost of nuclear fuel due to an 11% increase in the cost of nuclear fuel consumed and a 2% increase in MWh generated with nuclear fuel. The table below details the sources and costs of energy for 2013, 2012 and 2011. Fuel Type Cost Natural Gas ................ $ Coal ............................ Nuclear....................... Total.................... Purchased power ........ Total energy ........ $ (in thousands) 164,139 13,680 48,949 226,768 62,363 289,131 Fuel Type Cost (in thousands) 2013 MWh 3,686,823 635,717 4,966,233 9,288,773 1,547,930 10,836,703 2011 MWh Natural Gas ................ $ Coal ............................ Nuclear....................... Total.................... Purchased power ........ Total energy ........ $ 164,260 (a) 15,273 (b) 43,974 223,507 75,149 298,656 3,346,789 647,932 4,942,055 8,936,776 2,135,124 11,071,900 $ $ Cost per MWh 44.52 21.52 9.86 24.41 40.29 26.68 Cost (in thousands) 127,833 $ 13,604 49,639 191,076 60,251 251,327 $ 2012 MWh Cost per MWh $ 3,561,253 655,108 5,045,772 9,262,133 1,768,810 11,030,943 35.90 20.77 9.84 20.63 34.06 22.78 Cost per MWh 50.02 19.97 8.90 25.10 35.20 27.05 _____________________ (a) Natural gas costs exclude $3.2 million of energy expenses capitalized related to Newman Unit 5 pre-commercial testing recorded in 2011. Coal costs include $2.3 million adjustment for final coal reclamation amortization in accordance with PUCT Docket No. 38361 recorded in 2011. (b) 35 Table of Contents Other operations expense Other operations expense increased $0.6 million or 0.3% in 2013 compared to 2012 primarily due to increased administrative and general expense of $2.9 million due to increased outside services of $3.8 million related to software systems support and improvements and consulting and legal services related to the analysis of our future involvement at the Four Corners Generating Station. These increases were partially offset by decreased customer care expenses of $1.7 million primarily related to a decrease in our provision for uncollectible customer accounts reflecting improved collection efforts and decreased power production operation expense at Palo Verde of $1.4 million. Other operations expense increased $7.0 million or 3.0% in 2012 compared to 2011 primarily due to: (i) increased pension and benefits expense of $5.5 million reflecting changes in actuarial assumptions used to calculate expenses for our pension plans; (ii) increased power production operation expense at both Palo Verde and our fossil-fuel generating plants; and (iii) increased distribution operations expense. These increases were partially offset by decreased customer care expenses related to a decrease in our provision for uncollectible customer accounts reflecting improved collection efforts. Maintenance expense Maintenance expenses increased $0.7 million or 1.2% in 2013 compared to 2012 due to an increase in maintenance expense for our distribution system. Maintenance expenses decreased $1.8 million or 2.8% in 2012 compared to 2011 due primarily to decreased maintenance expense at Palo Verde of $3.2 million as a result of decreased maintenance during refueling outages in 2012 compared to refueling outages in 2011 partially offset by increased maintenance expense at our fossil-fuel generating plants. Depreciation and amortization expense Depreciation and amortization expense increased $1.1 million or 1.4% in 2013 compared to 2012 expense due to an increase in depreciable plant including Rio Grande Unit 9. The increase was partially offset by decreased depreciation expense due to reduced depreciation rates on gas-fired generating units and on transmission and distribution plant as a result of the Texas rate case settlement in May 2012. Depreciation and amortization expense decreased $2.8 million or 3.4% in 2012 compared to 2011 due to a reduction in depreciation rates for Palo Verde reflecting the approval of a license extension for Palo Verde by the NRC in April 2011, and reduced depreciation rates on gas-fired generating units and on transmission and distribution plant as a result of the 2012 Texas rate case settlement discussed above. The depreciation rate reductions were partially offset by higher depreciation expense due to an increase in depreciable plant. Taxes other than income taxes Taxes other than income taxes increased $0.3 million or 0.5% in 2013 compared to 2012 primarily due to increased property taxes which were partially offset by a reduction in revenue related taxes. Taxes other than income taxes increased $1.9 million or 3.4% in 2012 compared to 2011 primarily due to increased revenue-related taxes and increased property taxes in New Mexico. Other income (deductions) Other income (deductions) increased $0.2 million or 1.5% in 2013 compared to 2012 primarily as a result of increased investment and interest income due to realized gains on equity investments in our decommissioning trusts in 2013 compared to net unrealized and realized losses on equity investments in our decommissioning trusts in 2012 and increased allowance for equity funds used during construction ("AEFUDC") due to higher balances of construction work in progress in 2013. This increase was partially offset by increased miscellaneous deductions in 2013 due to the timing and amount of charitable donations and gains recognized on the sale of assets in 2012 with no comparable amounts in 2013. Other income (deductions) increased $2.6 million or 22.4% in 2012 compared to 2011 primarily as a result of increased AEFUDC of $1.3 million due to higher balances of construction work in progress in 2012, and a $1.1 million gain recognized on the sale of assets with no comparable amount in 2011. Interest charges (credits) Interest charges (credits) increased $2.8 million or 6.2% in 2013 compared to 2012 primarily due to interest on $150 million of 3.3% senior notes issued in December 2012 partially offset by (i) a decrease in interest on short-term borrowings for working capital purposes; (ii) the refunding and remarketing of two series of pollution control bonds at lower rates in August 2012; and (iii) increased allowance for borrowed funds used during construction ("ABFUDC") as a result of higher balances of construction work in progress in 2013. 36 Table of Contents Interest charges (credits) decreased $0.1 million or 0.3% in 2012 compared to 2011 primarily due to increased ABFUDC as a result of higher balances of construction work in progress in 2012 partially offset by interest expense on the $150 million in aggregate principal amount of 3.30% Senior Notes issued in December 2012. Income tax expense Income tax expense decreased by $3.3 million or 7.1% in 2013 compared to 2012 primarily due to a decrease in pre-tax income and a decrease in state income taxes due to positive developments in state income tax audits and settlements. Income tax expense decreased by $6.7 million or 12.5% in 2012 compared to 2011 primarily due to a decrease in pre-tax income. New accounting standards In February 2013, the FASB issued new guidance (ASU 2013-02, Comprehensive Income (Topic 220)) to improve the reporting of reclassifications out of accumulated other comprehensive income (loss). ASU 2013-02 requires an entity to report the effect of significant reclassifications out of accumulated other comprehensive income (loss) on the respective line items in net income if the amount being reclassified is required under FASB guidance to be reclassified in its entirety to net income in the same reporting period. For other amounts that are not required under FASB guidance to be reclassified in their entirety to net income in the same reporting period, an entity is required to cross-reference other disclosures required under FASB guidance that provide additional detail about those amounts. Substantially all of the information that ASU 2013-02 requires is already required to be disclosed elsewhere in the financial statements under FASB guidance. However, the new requirement to present information about amounts reclassified out of accumulated other comprehensive income (loss) and their corresponding effect on net income now requires the presentation in one place, information about significant amounts reclassified and, in some cases, cross-references to related footnote disclosures. ASU 2013-02 became effective prospectively for reporting periods beginning after December 15, 2012. We implemented ASU 2013-02 in the first quarter of 2013 and have presented the corresponding effects of components reclassified out of accumulated other comprehensive income (loss) with cross-references to other disclosures or the respective line items in net income in Note H of the Notes to the Financial Statements. In July 2013, the FASB issued new guidance (ASU 2013-11, Income Taxes (Topic 740)) to eliminate the diversity in the financial statement presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. ASU 2013-11 requires an entity to present an unrecognized tax benefit in the financial statements as a reduction to a deferred tax asset for a net operating loss carryforward, a similar tax loss, or a tax credit carryforward, except in certain circumstances when it would be reflected as a liability. ASU 2013-11 is effective prospectively for all unrecognized tax benefits that exist for reporting periods beginning after December 15, 2013 and early adoption is permitted. Retrospective application is also permitted. We anticipate implementing ASU 2013-11 in the first quarter of 2014. We are currently assessing the future impact of this ASU, however it is not expected to have a significant impact on our statement of operations or statements of cash flows. 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 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, 2013, our capital structure, including common stock, long-term debt, and short-term borrowings under the RCF, consisted of 48.2% common stock equity and 51.8% debt. At December 31, 2013, we had on hand $25.6 million in cash and cash equivalents. Based on current projections, we believe that we will have adequate liquidity through our current cash balances, cash from operations, and available borrowings under the RCF to meet all of our anticipated cash requirements for the next twelve months. We may issue long-term debt in the capital markets to finance capital requirements in 2014. Our principal liquidity requirements in the near-term are expected to consist of capital expenditures to expand and support electric service obligations, expenditures for nuclear fuel inventory, interest payments on our indebtedness, cash dividend payments, operating expenses including fuel costs, maintenance costs, and taxes. Capital Requirements. During the twelve months ended December 31, 2013, our capital requirements primarily consisted of expenditures for the construction and purchase of electric utility plant, cash dividend payments, and purchases of nuclear fuel. 37 Table of Contents Projected utility construction expenditures are to expand and update our transmission and distribution systems, add new generation, and make capital improvements and replacements at Palo Verde and other generating facilities. Rio Grande Unit 9, an aeroderivative gas turbine unit with a net dependable generating capacity of 87 MW, was completed and entered commercial operation on May 13, 2013. The total cost for this unit, including AFUDC, was approximately $95 million, of which approximately $12.4 million was incurred during 2013. We have purchased land for a new plant site, the Montana Power Station ("the MPS"), which will initially consist of two natural gas-fired 88 MW simple-cycle aeroderivative combustion turbines. The construction costs for the four units of the MPS may increase, and the construction schedule, associated expenditures and the in-service dates could be delayed, if the Company does not receive air permits by the end of the third quarter of 2014. For a full discussion of the MPS air permits see Part I, Item 1, "Regulation". We began constructing certain components of the MPS in 2013 and the estimated costs of the first two (of four) units is $165.1 million, including AFUDC. As of December 31, 2013, we had expended $108.7 million on the MPS, including AFUDC, of which $ 73.1 million was incurred during 2013. Estimated construction expenditures for all capital projects for 2014 are approximately $327 million. See Part I, Item 1, "Business - Construction Program". Cash capital expenditures for new electric plant were $237.4 million in the twelve months ended December 31, 2013 and $202.4 million in the twelve months ended December 31, 2012. On December 30, 2013, we paid a quarterly cash dividend of $0.265 per share or $10.7 million of quarterly dividends to shareholders of record on December 13, 2013. We paid a total of $42.0 million in cash dividends during the twelve months ended December 31, 2013. On January 23, 2014, our Board of Directors declared a quarterly cash dividend of $0.265 per share payable on March 31, 2014 to shareholders of record on March 14, 2014 which will require cash of $10.7 million. We expect to continue paying quarterly dividends during 2014 and we expect to review the dividend policy in the second quarter of 2014. At the current payout rate, we would expect to pay total cash dividends of approximately $42.8 million during 2014. In addition, while we do not currently anticipate repurchasing shares in 2014, we may repurchase common stock in the future. Under our program, purchases can be made at open market prices or in private transactions, and repurchased shares are available for issuance under employee benefit and stock incentive plans, or may be retired. No shares of common stock were repurchased in 2013 or 2012. As of December 31, 2013, 393,816 shares remain eligible for repurchase. We will continue to maintain a prudent level of liquidity as well as take market conditions for debt and equity securities into account. With the initiation of a dividend in early 2011, we are moving toward primarily utilizing the distribution of dividends to maintain a balanced capital structure, supplemented by share repurchases when appropriate. Our liquidity needs can fluctuate quickly based on fuel prices and other factors and we are continuing to make investments in new electric plant and other assets in order to reliably serve our customers. In light of these factors, we expect it will be a number of years before we achieve a dividend payout equivalent to industry average. Our cash requirements for federal and state income taxes vary from year to year based on taxable income, which is influenced by the timing of revenues and expenses recognized for income tax purposes. Due to net operating loss carryforwards resulting from accelerated depreciation deductions and utilization of alternative minimum tax credits, income tax payments are expected to be minimal in 2014. We continually evaluate our funding requirements related to our retirement plans, other postretirement benefit plans, and decommissioning trust funds. We contributed $16.9 million and $19.9 million to our retirement plans during the twelve months ended December 31, 2013 and 2012, respectively. We also contributed $3.1 million and $3.7 million to our other postretirement benefit plan during the twelve months ended December 31, 2013 and 2012, respectively. We contributed $4.5 million to our decommissioning trust funds in both 2013 and 2012. We are in compliance with the funding requirements of the federal government for our benefit plans and decommissioning trust. We will continue to review our funding for these plans in order to meet our future obligations. Capital Resources. Cash from operations has been our primary source for funding capital requirements. Cash from operations was $247.5 million in 2013 and $273.1 million in 2012. In 2013 and 2012, cash from operations was impacted by a rate reduction in Texas. In the settlement of our 2012 Texas retail rate case in PUCT Docket No. 40094, we agreed to a reduction in our non- fuel base rates of $15 million annually, with the decrease being allocated primarily to Texas commercial and industrial customer classes. The rate decrease was effective May 1, 2012, and our non-fuel base revenues were reduced by approximately $3.3 million in 2013 compared to 2012 and $11.7 million in 2012 compared to 2011 as a result of these lower rates. Cash from operations has also been impacted by the timing of the recovery of fuel costs through fuel recovery mechanisms in Texas and New Mexico and our sales for resale customer. We recover actual fuel costs from customers through fuel adjustment mechanisms in Texas, New Mexico, and from our sales for resale customer. We record deferred fuel revenues for the under- recovery or over-recovery of fuel costs until they can be recovered from or refunded to customers. In Texas, fuel costs are recovered through a fixed fuel factor. 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 38 Table of Contents gas. On October 1, 2013, we implemented an increased fixed fuel factor charged to our Texas retail customers which was based upon a formula that reflects projected prices for natural gas. During the twelve months ended December 31, 2013, net fuel recoveries resulted in decreased cash from operations when compared to the same period in 2012. During the twelve months ended December 31, 2013, the Company had a fuel under-recovery of $10.8 million compared to an over-recovery of fuel costs, net of refunds, of $11.7 million during the twelve months ended December 31, 2012. At December 31, 2013, we had a net fuel under-recovery balance of $6.2 million, including an under-recovery balance of $7.2 million in Texas and an over-recovery balance of $1.0 million in New Mexico. On December 6, 2012, we issued $150 million in aggregate principal amount of 3.30% senior notes due December 15, 2022. The gross proceeds from the issuance of the senior notes were $149.7 million, net of a $0.3 million discount before commissions and expenses and the effective interest rate was 3.43%. On August 28, 2012, we completed a refunding transaction related to our 4.80% 2005 Series A (El Paso Electric Company Palo Verde Project) Pollution Control Refunding Revenue Bonds totaling $59.2 million in which new pollution control bonds totaling $59.2 million were issued at a fixed rate of 4.50%. The bonds are unsecured and will mature in 2042. On August 28, 2012, we also completed a remarketing transaction related to our 4.00% 2002 Series A (El Paso Electric Company Four Corners Project) Pollution Control Refunding Revenue Bonds totaling $33.3 million in which new pollution control bonds totaling $33.3 million were issued at a fixed rate of 1.875%. These bonds were unsecured and mature in 2032 subject to mandatory tender for purchase in 2017. We maintain an RCF for working capital and general corporate purposes and the financing of nuclear fuel through the RGRT. RGRT is the trust through which we finance our portion of nuclear fuel for Palo Verde and is consolidated in the Company's financial statements. On January 14, 2014, we amended and extended our $300 million RCF, which includes an option to expand the size to $400 million, upon the satisfaction of certain conditions including obtaining commitments from lenders or third party financial institutions. The amended facility extends the maturity from September 2016 to January 2019. In addition, we may extend the January 2019 maturity, subject to lenders' approval, by two additional one year periods. The terms of the agreement provide that amounts we borrow under the RCF may be used for working capital and general corporate purposes. The total amount borrowed for nuclear fuel by RGRT was $124.4 million at December 31, 2013, of which $14.4 million had been borrowed under the RCF and $110 million was borrowed through senior notes. Borrowings by RGRT for nuclear fuel were $132.2 million at December 31, 2012, of which $22.2 million had been borrowed under the RCF and $110 million was borrowed through senior notes. Interest costs on borrowings to finance nuclear fuel are accumulated by RGRT and charged to us as fuel is consumed and recovered from customers through fuel recovery charges. No borrowings were outstanding at December 31, 2013 or December 31, 2012, under the RCF for working capital and general corporate purposes. We believe we have adequate liquidity through our current cash balances, cash from operations, our RCF, and our favorable access to capital markets to meet all of our anticipated cash requirements for the next twelve months. In the fourth quarter of 2013, we received approval from the NMPRC and the FERC to incrementally issue up to $300 million of long-term debt and to guarantee the issuance of up to $50 million of new debt by RGRT to finance future purchases of nuclear fuel and to refinance existing nuclear fuel debt obligations. Obtaining the ability to issue up to $300 million of new long-term debt, from time to time, provides us with the flexibility to access the debt capital markets when needed and when conditions are favorable. We may decide to access the capital markets in the second half of 2014. 39 Table of Contents Contractual Obligations. Our contractual obligations as of December 31, 2013 are as follows (in thousands): Payments due by period Total 2014 2015 and 2016 2017 and 2018 2019 and Beyond Long-Term Debt (including interest): Senior notes (1)........................................... $ 1,536,175 Pollution control bonds (2) ......................... 466,003 RGRT Senior notes (3) ............................... 135,918 $ 40,200 $ 80,400 $ 80,400 $ 1,335,175 10,583 5,054 21,167 24,557 53,634 56,771 380,619 49,536 Financing Obligations (including interest): Revolving credit facility (4)........................ 14,555 14,555 Purchase Obligations: Power contracts........................................... 1,152 1,152 Fuel contracts: Coal (5)................................................ Gas (5) ................................................. Nuclear fuel (6).................................... Retirement Plans and Other Postretirement benefits (7) ......................................................... Decommissioning trust funds (8)....................... 28,902 374,650 105,323 13,870 152,637 Operating leases (9) ........................................... 10,514 Total ........................................... $ 2,839,699 _____________________ (1) 10,949 47,865 21,930 13,870 4,535 1,081 — — 17,953 83,233 32,961 — 9,071 1,628 — — — 75,079 29,762 — 9,071 850 — — — 168,473 20,670 — 129,960 6,955 $ 171,774 $ 270,970 $ 305,567 $ 2,091,388 (2) (3) (4) (5) (6) (7) (8) (9) We have three issuances of Senior Notes. In May 2005, we issued $400.0 million in aggregate principal amount of 6% Senior Notes due May 15, 2035. In June 2008, we issued $150.0 million in aggregate principal amount of 7.5% Senior Notes due March 15, 2038. In December 2012, we issued $150.0 million in aggregate principal amount of 3.3% Senior Notes due December 15, 2022. We have four series of pollution control bonds which are scheduled for remarketing and/or mandatory tender, one in 2017, two in 2040, and one in 2042. In 2010, the Company and RGRT entered into a Note Purchase Agreement for $110 million aggregate principal amount of senior notes consisting of: (a) $15 million aggregate principal amount of 3.67% RGRT Senior Notes, Series A, due August 15, 2015, (b) $50 million aggregate principal amount of 4.47% RGRT Senior Notes, Series B, due August 15, 2017 and (c) $45 million aggregate principal amount of 5.04% RGRT Senior Notes, Series C, due August 15, 2020. This reflects obligations outstanding under the $300 million RCF. At December 31, 2013, $14.4 million was borrowed by RGRT for nuclear fuel. This balance includes interest based on actual interest rates at the end of 2013 and assumes this amount will be outstanding for the entire year of 2014. Amount is based on the minimum volumes per the contract and market and/or contract price at the end of 2013. 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 2013. This obligation is based on our expected contributions and includes our minimum contractual funding requirements for the non-qualified retirement income plan and the other postretirement benefits for 2014. We have no minimum cash contractual funding requirement related to our retirement income plan or other postretirement benefits for 2014. However, we may decide to fund at higher levels and expect to contribute $13.9 million to our retirement plans in 2014, as disclosed in Part II, Item 8, Notes to Financial Statements, Note M, Employee Benefits. Minimum funding requirements for 2015 and beyond are not included due to the uncertainty of interest rates and the related return on assets. These obligations represent funding amounts approved in PUCT Docket No. 40094 and NMPRC Case No. 09-00171- UT. We lease land in El Paso adjacent to the Newman Power Station under a lease which expires in June 2033 with a renewal option of 25 years. In addition, we lease certain warehouse facilities in El Paso under a lease which expires in December 2015. We also have several other leases for office, parking facilities and equipment which expire within the next four years. 40 Table of Contents 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. 41 Table of Contents 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 $85.3 million and $90.6 million as of December 31, 2013 and 2012, respectively. A hypothetical 10% increase in interest rates would reduce the fair values of these funds by $1.2 million and $0.7 million based on their fair values at December 31, 2013 and 2012, respectively. Equity Price Risk Our decommissioning trust funds include marketable equity securities of approximately $122.9 million and $92.0 million at December 31, 2013 and 2012, respectively. A hypothetical 20% decrease in equity prices would reduce the fair values of these funds by $24.6 million and $18.4 million based on their fair values at December 31, 2013 and 2012, respectively. Declines in market prices could require that additional amounts be contributed to our decommissioning trusts to maintain minimum funding requirements. We will not have a requirement to expend monies held in trust before 2044 or a later period when we begin to decommission Palo Verde. Commodity Price Risk We utilize contracts of various durations for the purchase of natural gas, uranium concentrates and coal to effectively manage our available fuel portfolio. These agreements contain variable pricing provisions and are settled by physical delivery. The fuel contracts with variable pricing provisions, as well as substantially all of our purchased power requirements, are exposed to fluctuations in prices due to unpredictable factors, including weather and various other worldwide events, which impact supply and demand. However, our exposure to fuel and purchased power price risk is substantially mitigated through the operation of the PUCT and NMPRC rules and our fuel clauses, as discussed previously. In the normal course of business, we enter into contracts of various durations for the forward sales and purchases of electricity to effectively manage our available generating capacity and supply needs. Such contracts include forward contracts for the sale of generating capacity and energy during periods when our available power resources are expected to exceed the requirements of our retail native load and sales for resale. We also enter into forward contracts for the purchase of wholesale capacity and energy during periods when the market price of electricity is below our expected incremental power production costs or to supplement our generating capacity when demand is anticipated to exceed such capacity. As of January 31, 2014, 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 which qualify for the "normal purchases and normal sales" exception provided in FASB guidance for accounting for derivative instruments and hedging activities and are not recorded at their fair value in our financial statements. Because of the operation of the PUCT and the NMPRC rules and our fuel clauses, these contracts do not expose us to significant commodity price risk. 42 Table of Contents 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, 2013. In making this assessment, the Company’s management used the criteria set forth by the 1992 Committee of Sponsoring Organizations of the Treadway Commission in Internal Control-Integrated Framework. Based on its assessment, management believes that, as of December 31, 2013, 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 45 of this report. 43 Table of Contents Item 8. Financial Statements and Supplementary Data INDEX TO FINANCIAL STATEMENTS Report of Independent Registered Public Accounting Firm ................................................................................................... Balance Sheets as of December 31, 2013 and 2012................................................................................................................ Statements of Operations for the years ended December 31, 2013, 2012 and 2011............................................................... Statements of Comprehensive Operations for the years ended December 31, 2013, 2012 and 2011.................................... Statements of Changes in Common Stock Equity for the years ended December 31, 2013, 2012 and 2011........................ Statements of Cash Flows for the years ended December 31, 2013, 2012 and 2011 ............................................................. Notes to Financial Statements................................................................................................................................................. Page 45 46 48 49 50 51 52 44 Table of Contents Report of Independent Registered Public Accounting Firm The Board of Directors and Shareholders El Paso Electric Company: We have audited the accompanying balance sheets of El Paso Electric Company as of December 31, 2013 and 2012, 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, 2013. We also have audited El Paso Electric Company’s internal control over financial reporting as of December 31, 2013, based on criteria established in Internal Control - Integrated Framework (1992) 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, 2013 and 2012, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2013, 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, 2013, based on criteria established in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission. /s/ KPMG LLP Houston, Texas February 26, 2014 45 Table of Contents EL PASO ELECTRIC COMPANY BALANCE SHEETS Utility plant: ASSETS (In thousands) December 31, 2013 2012 Electric plant in service ........................................................................................................... $ 3,076,549 (1,214,088) Less accumulated depreciation and amortization.................................................................... 1,862,461 Net plant in service........................................................................................................... 282,647 Construction work in progress................................................................................................. $ 2,857,913 (1,162,483) 1,695,430 287,358 Nuclear fuel; includes fuel in process of $48,492 and $56,129, respectively ......................... Less accumulated amortization ............................................................................................... Net nuclear fuel ................................................................................................................ Net utility plant ....................................................................................................... 188,185 (75,820) 112,365 189,921 (70,366) 119,555 2,257,473 2,102,343 Current assets: Cash and cash equivalents ....................................................................................................... Accounts receivable, principally trade, net of allowance for doubtful accounts of $2,261 and $2,906, respectively .......................................................................................................... Accumulated deferred income taxes ....................................................................................... Inventories, at cost................................................................................................................... Undercollection of fuel revenues............................................................................................. Prepayments and other ............................................................................................................ Total current assets ................................................................................................. 25,592 111,057 65,350 26,965 45,942 7,248 7,694 62,900 20,292 42,358 — 9,627 178,791 246,234 Deferred charges and other assets: Decommissioning trust funds .................................................................................................. Regulatory assets ..................................................................................................................... Other ........................................................................................................................................ Total deferred charges and other assets .................................................................. 350,024 Total assets...................................................................................................... $ 2,786,288 214,095 101,050 34,879 187,053 101,590 31,830 320,473 $ 2,669,050 See accompanying notes to financial statements. 46 Table of Contents 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, 65,639,091 and 65,520,551 shares issued, and 120,534 and 84,446 restricted shares, respectively ................ $ Capital in excess of stated value.............................................................................................. Retained earnings .................................................................................................................... Accumulated other comprehensive income (loss), net of tax.................................................. Treasury stock, 25,492,919 shares at cost ............................................................................... Common stock equity....................................................................................................... Long-term debt ........................................................................................................................ Total capitalization.................................................................................................. Current liabilities: Short-term borrowings under the revolving credit facility...................................................... Accounts payable, principally trade ........................................................................................ Taxes accrued .......................................................................................................................... Interest accrued........................................................................................................................ Overcollection of fuel revenues............................................................................................... Other ........................................................................................................................................ Total current liabilities............................................................................................ Deferred credits and other liabilities: Accumulated deferred income taxes ....................................................................................... Accrued pension liability......................................................................................................... Accrued postretirement benefit liability.................................................................................. Asset retirement obligation...................................................................................................... Regulatory liabilities ............................................................................................................... Other ........................................................................................................................................ Total deferred credits and other liabilities .............................................................. Commitments and contingencies December 31, 2013 2012 $ 65,760 314,443 985,665 2,612 1,368,480 (424,647) 943,833 999,620 1,943,453 65,605 310,994 939,131 (66,084) 1,249,646 (424,647) 824,999 999,535 1,824,534 14,352 61,795 25,206 12,189 1,048 22,932 137,522 449,925 84,012 50,655 65,214 26,416 29,091 705,313 22,155 61,581 29,248 12,127 4,643 21,995 151,749 358,674 125,690 99,170 62,784 22,179 24,270 692,767 Total capitalization and liabilities................................................................ $ 2,786,288 $ 2,669,050 See accompanying notes to financial statements. 47 Table of Contents EL PASO ELECTRIC COMPANY STATEMENTS OF OPERATIONS (In thousands except for share data) Operating revenues ............................................................................................. $ Energy expenses: Fuel ................................................................................................................ Purchased and interchanged power................................................................ Operating revenues net of energy expenses ...................................................... Other operating expenses: Years Ended December 31, 2013 2012 2011 890,362 $ 852,881 $ 918,013 226,768 62,363 289,131 601,231 191,076 60,251 251,327 601,554 223,507 75,149 298,656 619,357 Other operations............................................................................................. 237,155 236,558 229,570 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. 61,068 79,626 57,747 435,596 165,635 10,008 7,033 909 (3,635) 14,315 58,635 431 (5,299) (6,055) 47,712 132,238 43,655 88,583 2.20 2.20 1.045 $ $ $ $ 60,339 78,556 57,443 432,896 168,658 9,427 5,275 1,415 (2,013) 14,104 54,632 1,190 (5,312) (5,573) 44,937 137,825 46,979 90,846 2.27 2.26 0.97 $ $ $ $ 62,092 81,331 55,561 428,554 190,803 8,161 5,664 885 (3,187) 11,523 54,115 989 (5,177) (4,848) 45,079 157,247 53,708 103,539 2.49 2.48 0.66 40,114,594 39,974,022 41,349,883 40,126,647 40,055,581 41,587,059 48 Table of Contents EL PASO ELECTRIC COMPANY STATEMENTS OF COMPREHENSIVE OPERATIONS (In thousands) Years Ended December 31, 2013 2012 2011 88,583 $ 90,846 $ 103,539 82,964 97 (5,560) 10,472 17,699 (553) 411 105,530 (33,566) (3,100) (168) (36,834) 68,696 (2,109) — (77,678) — (5,762) 11,971 9,927 1,042 385 15,454 (1,464) (2,438) (131) (4,033) 11,421 (5,812) 6,505 1,570 1,358 361 (73,696) 30,134 (563) (203) 29,368 (44,328) 59,211 157,279 $ 102,267 $ Net income ................................................................................................................ $ Other comprehensive income (loss): Unrecognized pension and postretirement 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 arising during period ...................................................... Reclassification adjustments for net (gains) losses 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 postretirement benefit costs ............................. Net unrealized gains 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. 49 Table of Contents EL PASO ELECTRIC COMPANY STATEMENTS OF CHANGES IN COMMON STOCK EQUITY (In thousands except for share data) Common Stock Shares 65,265,060 Amount $ 65,265 Capital in Excess of Stated Value 305,068 $ Accumulated Other Comprehensive Income (Loss), Net of Tax Retained Earnings $ 810,858 $ (33,177) 118,110 40,895 (23,702) (2,200) 53,910 118 41 (24) (2) 54 3,087 587 (715) 1,112 638 Treasury Stock Shares 22,693,995 $ Amount (337,639) $ Common Stock Equity 810,375 65,452,073 65,452 309,777 887,174 (77,505) 2,798,924 25,492,919 (87,008) (424,647) 103,539 (27,223) (44,328) 87,428 174,038 (52,778) (88,100) 32,336 87 174 (52) (88) 32 1,691 1,019 (1,770) (1,206) 1,101 382 Balances at December 31, 2010........................................... Restricted common stock grants and deferred compensation ............................................................. Performance share awards vested .................................. Stock awards withheld for taxes .................................... Forfeited restricted common stock................................. Deferred taxes on stock incentive plan .......................... Stock options exercised.................................................. Net income ..................................................................... Other comprehensive loss .............................................. Dividends declared......................................................... Treasury stock acquired, at cost..................................... Balances at December 31, 2011........................................... Restricted common stock grants and deferred compensation ............................................................. Performance share awards vested .................................. Stock awards withheld for taxes .................................... Forfeited restricted common stock................................. Deferred taxes on stock incentive plan .......................... Stock options exercised.................................................. Net income ..................................................................... Other comprehensive income ........................................ Dividends declared Balances at December 31, 2012........................................... 65,604,997 65,605 310,994 Restricted common stock grants and deferred compensation ............................................................. Performance share awards vested .................................. Stock awards withheld for taxes .................................... Forfeited restricted common stock................................. Deferred taxes on stock incentive plan .......................... Stock options exercised.................................................. Compensation paid in shares ......................................... Net income ..................................................................... Other comprehensive income ........................................ Dividends declared......................................................... Balances at December 31, 2013........................................... See accompanying notes to financial statements. 96,279 64,275 (23,808) (1,549) 15,000 4,431 96 64 (23) (1) 15 4 2,702 785 (788) 427 177 146 65,759,625 $ 65,760 $ 314,443 $ 50 90,846 (38,889) 939,131 11,421 (66,084) 25,492,919 (424,647) 88,583 (42,049) 985,665 $ 68,696 2,612 25,492,919 $ (424,647) $ 3,205 628 (739) (2) 1,112 692 103,539 (44,328) (27,223) (87,008) 760,251 1,778 1,193 (1,822) (1,294) 1,101 414 90,846 11,421 (38,889) 824,999 2,798 849 (811) (1) 427 192 150 88,583 68,696 (42,049) 943,833 Table of Contents EL PASO ELECTRIC COMPANY STATEMENTS OF CASH FLOWS (In thousands) 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 .............................................................................. Other operating activities .......................................................................................... Change in: Accounts receivable .................................................................................................. Inventories ................................................................................................................. Net overcollection (undercollection) 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, $4.5 million and $8.3 million, respectively ......................................................................................................... Sales and maturities ................................................................................................... Proceeds from sale of investments in debt securities ......................................................... Other investing activities ................................................................................................... Net cash used for investing activities .......................................................... Cash Flows From Financing Activities: Repurchases of common stock ........................................................................................... Dividends paid ................................................................................................................... Borrowings under the revolving credit facility: Proceeds .................................................................................................................... Payments ................................................................................................................... Pollution control bonds: Proceeds .................................................................................................................... Payments ................................................................................................................... Proceeds from issuance of senior notes ............................................................................. Other financing activities ................................................................................................... Net cash provided by (used for) financing activities .................................. Net increase (decrease) in cash and cash equivalents ............................................................ Cash and cash equivalents at beginning of period ................................................................. Years Ended December 31, 2013 2012 2011 88,583 $ 90,846 $ 103,539 79,626 42,537 44,678 (10,008) 16,556 (925) (2,450) (3,673) (10,843) (4,295) 8,180 (627) 958 (822) 247,475 78,556 42,953 43,561 (9,427) 14,724 (479) 13,448 (1,926) 11,668 (2,784) 1,725 (3,054) 78 (6,781) 273,108 81,331 37,018 45,688 (8,161) 19,875 1,036 (4,663) (3,750) (26,001) (2,538) 4,401 11,915 (2,262) (5,911) 251,517 (237,411) (30,535) (202,387) (46,009) (178,041) (39,551) (16,063) (5,299) 10,008 (65,491) 56,148 — 5,879 (282,764) — (42,049) 44,883 (52,686) — — — (324) (50,176) (85,465) 111,057 (15,000) (5,312) 9,427 (107,705) 98,542 — 2,390 (266,054) — (38,889) 234,575 (245,799) 92,535 (92,535) 149,682 (3,774) 95,795 102,849 8,208 (13,009) (5,177) 8,161 (95,441) 82,926 2,000 727 (237,405) (86,508) (27,223) 120,450 (91,775) — — — (32) (85,088) (70,976) 79,184 8,208 Cash and cash equivalents at end of period ........................................................................... $ 25,592 $ 111,057 $ See accompanying notes to financial statements. 51 Table of Contents 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 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 53 56 56 60 61 64 65 70 72 74 76 79 80 90 91 95 96 52 Table of Contents 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. El Paso Electric Company also serves a full requirements wholesale customer in Texas. Dissolution of Subsidiary. MiraSol Energy Services, Inc. ("MiraSol"), the Company’s wholly owned subsidiary, provided energy efficiency products and discontinued these activities in 2002. MiraSol has had no material effect on the Company’s previously reported consolidated financial statements for the years ended December 31, 2012 and December 31, 2011. The Company dissolved MiraSol in the fourth quarter of 2013. MiraSol’s net assets and stockholders’ equity totaled less than $0.1 million and the dissolution of MiraSol had no material effect on the Company’s financial statements for the twelve months ended December 31, 2013. Use of Estimates. The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Basis of Presentation. The Company maintains its accounts in accordance with the Uniform System of Accounts prescribed by the Federal Energy Regulatory Commission (the "FERC"). Application of FASB Guidance for Regulated Operations. Regulated electric utilities typically prepare their financial statements in accordance with the Financial Accounting Standards Board ("FASB") guidance for regulated operations. FASB guidance for regulated operations requires the Company to include an allowance for equity and borrowed funds used during construction ("AEFUDC" and "ABFUDC") as a cost of construction of electric plant in service. AEFUDC is recognized as income and ABFUDC is shown as capitalized interest charges in the Company’s statement of operations. FASB guidance for regulated operations also requires the Company to show certain recoverable costs as either assets or liabilities on a utility’s balance sheet if the regulator provides assurance that these costs will be charged to and collected from the utility’s customers (or has already permitted such cost recovery) or will be credited or refunded to the utility’s customers. The resulting regulatory assets or liabilities are amortized in subsequent periods based upon the respective amortization periods reflected in a utility’s regulated rates. See Note D. The Company applies FASB guidance for regulated operations for all three of the jurisdictions in which it operates. 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 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 2013, 2012 and 2011 was 2.61%, 2.64%, and 2.80%, respectively. When property subject to composite depreciation is retired or otherwise disposed of in the normal course of business, its cost – together with the cost of removal, less salvage – is charged to accumulated depreciation. For other property dispositions, the applicable cost and accumulated depreciation is removed from the balance sheet accounts and a gain or loss is recognized. The cost of nuclear fuel is amortized to fuel expense on a units-of-production basis. A provision for spent fuel disposal costs is charged to expense based on the funding requirements of the Department of Energy (the "DOE") for disposal cost of approximately one-tenth of one cent on each kWh generated. The Company is also amortizing its share of costs associated with on-site spent fuel storage casks at Palo Verde over the burn period of the fuel that will necessitate the use of the storage casks. See Note E. Impairment of Long-Lived Assets. Long-lived assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to estimated undiscounted future cash flows expected to be generated by the asset. If the carrying amount of an asset exceeds its estimated undiscounted future cash flows, an impairment charge is recognized for the amount by which the carrying amount of the asset exceeds the fair value of the asset. 53 Table of Contents 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 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 AFUDC rates used in 2013, 2012 and 2011 were 8.10%, 8.53% and 8.54%, respectively. Asset Retirement Obligation. FASB guidance sets forth accounting requirements for the recognition and measurement of liabilities associated with the retirement of tangible long-lived assets. An asset retirement obligation ("ARO") associated with long-lived assets included within the scope of FASB guidance is that for which a legal obligation exists under enacted laws, statutes, written or oral contracts, including obligations arising under the doctrine of promissory estoppel and legal obligations to perform an asset retirement activity even if the timing and/or settlement are conditioned on a future event that may or may not be within the control of an entity. See Note F. Under FASB guidance, these liabilities are recognized as incurred if a reasonable estimate of fair value can be established and are capitalized as part of the cost of the related tangible long-lived assets. The Company records the increase in the ARO due to the passage of time as an operating expense (accretion expense). Cash and Cash Equivalents. All temporary cash investments with an original maturity of three months or less are considered cash equivalents. Investments. The Company’s marketable securities, included in decommissioning trust funds in the balance sheets, are reported at fair value and consist of cash, equity securities and municipal, federal and corporate bonds in trust funds established for decommissioning of its interest in Palo Verde. Such marketable securities are classified as "available-for-sale" securities and, as such, unrealized gains and losses are included in accumulated other comprehensive loss as a separate component of common stock equity. However, if declines in fair value of marketable securities below original cost basis are determined to be other than temporary, then the declines are reported as losses in the statement of operations and a new cost basis is established for the affected securities at fair value. Gains and losses are determined using the cost of the security based on the specific identification basis. See Note O. Derivative Accounting. Accounting for derivative instruments and hedging activities requires the recognition of derivatives as either assets or liabilities in the balance sheet with measurement of those instruments at fair value. Any changes in the fair value of these instruments are recorded in earnings or other comprehensive income. See Note O. Inventories. Inventories, primarily parts, materials, supplies, fuel oil and natural gas are stated at average cost not to exceed recoverable cost. Operating Revenues Net of Energy Expenses. The Company accrues revenues for services rendered, including unbilled electric service revenues. Energy expenses are stated at actual cost incurred. The Company’s Texas retail customers are billed under base rates and a fixed fuel factor approved by the Public Utility Commission of Texas ("PUCT"). The Company’s New Mexico retail customers and its sales for resale customer are billed under base rates and a fuel adjustment clause which is adjusted monthly, as approved by the New Mexico Public Regulation Commission ("NMPRC") and the FERC. The Company’s recovery of energy expenses is subject to periodic reconciliations of actual energy expenses incurred to actual fuel revenues collected. The difference between energy expenses incurred and fuel revenues charged to customers is reflected as over/undercollection of fuel revenues in the balance sheets. See Note C. Revenues. Revenues related to the sale of electricity are generally recorded when service is rendered or electricity is delivered to customers. The billing of electricity sales to retail customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. Unbilled revenues are estimated based on monthly generation volumes and by applying an average revenue/kWh to the number of estimated kWhs delivered but not billed. Accounts receivable included accrued unbilled revenues of $19.8 million and $17.9 million at December 31, 2013 and 2012, 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 existing collections environment. Additions, deductions and balances for allowance for doubtful accounts for 2013, 2012 and 2011 are as follows (in thousands): 54 Table of Contents EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS 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 ................................................................................. $ 2013 2012 2011 2,906 $ 3,015 $ 2,885 2,098 1,929 4,672 2,261 $ 3,087 2,041 5,237 2,906 $ 6,209 2,034 8,113 3,015 Income Taxes. The Company accounts for federal and state income taxes under the asset and liability method of accounting for income taxes. Deferred income taxes are recognized for the estimated future tax consequences of "temporary differences" by applying enacted statutory tax rates for each taxable jurisdiction applicable to future years to differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities. Certain temporary differences are accorded flow- through treatment by the Company's regulators and impact the Company's effective tax rate. FASB guidance requires that rate- regulated companies record deferred income taxes for temporary differences accorded flow-through treatment at the direction of the regulatory commission. The resulting deferred tax assets and liabilities are recorded at the expected cash flow to be reflected in future rates. Because the Company's regulators have consistently permitted the recovery of tax effects previously flowed-through earnings, the Company has recorded regulatory liabilities and assets offsetting such deferred tax assets and liabilities. The effect on deferred tax assets and liabilities of a change in tax rate is recognized in income in the period that includes the enactment date. The Company recognizes tax assets and liabilities for uncertain tax positions in accordance with the recognition and measurement criteria of FASB guidance for uncertainty in income taxes. See Note J. Earnings per Share. The Company’s restricted stock awards are participating securities and earnings per share must be calculated using the two-class method in both the basic and diluted earnings per share calculations. For the basic earnings per share calculation, net income is allocated to the weighted average number of restricted stock awards and to the weighted average number of shares outstanding. The net income allocated to the weighted average number of shares outstanding is then divided by the weighted average number of shares outstanding to derive the basic earnings per share. For the diluted earnings per share, net income is allocated to the weighted average number of restricted stock awards and to the weighted average number of shares and dilutive potential shares outstanding. The Company’s dilutive potential shares outstanding amount is calculated using the treasury stock method for the unvested performance shares and outstanding stock options. Net income allocated to the weighted average number of shares and dilutive potential shares is then divided by the weighted average number of shares and dilutive potential shares outstanding to derive the diluted earnings per share. See Note G. Stock-Based Compensation. The Company has a stock-based long-term incentive plan. The Company is required under FASB guidance to measure the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award. Such costs are recognized over the period during which an employee is required to provide service in exchange for the award (the "requisite service period") which typically is the vesting period. Compensation cost is not recognized for anticipated forfeitures prior to vesting of equity instruments. See Note G. Pension and Postretirement Benefit Accounting. See Note M for a discussion of the Company’s accounting policies for its employee benefits. Reclassification. Certain amounts in the financial statements for 2012 and 2011 have been reclassified to conform with the 2013 presentation. 55 Table of Contents EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS B. New Accounting Standards In February 2013, the FASB issued new guidance (Accounting Standards Update ("ASU") 2013-02, Comprehensive Income (Topic 220)) to improve the reporting of reclassifications out of accumulated other comprehensive income (loss). ASU 2013-02 requires an entity to report the effect of significant reclassifications out of accumulated other comprehensive income (loss) on the respective line items in net income if the amount being reclassified is required under FASB guidance to be reclassified in its entirety to net income in the same reporting period. For other amounts that are not required under FASB guidance to be reclassified in their entirety to net income in the same reporting period, an entity is required to cross-reference other disclosures required under FASB guidance that provide additional detail about those amounts. Substantially all of the information that ASU 2013-02 requires is already required to be disclosed elsewhere in the financial statements under FASB guidance. However, the new requirement to present information about amounts reclassified out of accumulated other comprehensive income (loss) and their corresponding effect on net income now requires the presentation in one place, information about significant amounts reclassified and, in some cases, cross-references to related footnote disclosures. ASU 2013-02 became effective prospectively for reporting periods beginning after December 15, 2012. The Company implemented ASU 2013-02 in the first quarter of 2013 and has presented the corresponding effects of components reclassified out of accumulated other comprehensive income (loss) with cross-references to other disclosures or the respective line items in net income in Note H. In July 2013, the FASB issued new guidance (ASU 2013-11, Income Taxes (Topic 740)) to eliminate the diversity in the financial statement presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. ASU 2013-11 requires an entity to present an unrecognized tax benefit in the financial statements as a reduction to a deferred tax asset for a net operating loss carryforward, a similar tax loss, or a tax credit carryforward, except in certain circumstances when it would be reflected as a liability. ASU 2013-11 is effective prospectively for all unrecognized tax benefits that exist for reporting periods beginning after December 15, 2013 and early adoption is permitted. Retrospective application is also permitted. The Company anticipates implementing ASU 2013-11 in the first quarter of 2014.The Company is currently assessing the future impact of this ASU, however it is not expected to have a significant impact on the Company's statement of operations or statements of cash flows. C. Regulation General The rates and services of the Company are regulated by incorporated municipalities in Texas, the PUCT, the NMPRC, and the FERC. The PUCT and the NMPRC have jurisdiction to review municipal orders, ordinances and utility agreements regarding rates and services within their respective states and over certain other activities of the Company. The FERC has jurisdiction over the Company's wholesale (sales for resale) transactions, transmission service and compliance with federally-mandated reliability standards. The decisions of the PUCT, the NMPRC and the FERC are subject to judicial review. Texas Regulatory Matters 2012 Texas Retail Rate Case. The Company filed a rate increase request with the PUCT, Docket No. 40094, the City of El Paso, and other Texas cities on February 1, 2012. The rate filing was made in response to a resolution adopted by the El Paso City Council (the "Council") requiring the Company to show cause why its base rates for customers in the El Paso city limits should not be reduced. The filing at the PUCT also included a request to reconcile $356.5 million of fuel expense for the period July 1, 2009 through September 30, 2011. On April 17, 2012, the Council approved the settlement of the Company's 2012 Texas retail rate case and fuel reconciliation in PUCT Docket No. 40094. The PUCT issued a final order approving the settlement on May 23, 2012. Under the terms of the settlement, among other things, the Company agreed to: • A reduction in its non-fuel base rates of $15 million annually, with the decrease being allocated primarily to Texas retail commercial and industrial customer classes. The rate decrease was effective as of May 1, 2012; 56 Table of Contents EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS • Revised depreciation rates for the Company's gas-fired generating units and for transmission and distribution plant that lower depreciation expense by $4.1 million annually; • Continuation of the 10.125% return on equity for the purpose of calculating the allowance for funds used during construction; and • A two-year amortization of rate case expenses, none of which will be included in future regulatory proceedings. As part of the settlement, the Company agreed to withdraw its request to reconcile fuel costs for the period from July 1, 2009 through September 30, 2011 and submit a future fuel reconciliation request covering the period beginning July 1, 2009 and ending no later than June 30, 2013 by December 31, 2013 or as part of its next rate case, if earlier. The settlement also provides for the continuation of the energy efficiency cost recovery factor and the military base discount recovery factor. Both of these surcharges require annual filings to reconcile and revise the recovery factors. 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. The Company filed the following petition with the PUCT to refund fuel cost over-recoveries, due primarily to fluctuations in natural gas markets and consumption levels. The table summarizes the docket number assigned by the PUCT, the date the Company filed the petition and the date a final order was issued by the PUCT approving the refund to customers. The fuel cost over-recovery period represents the months in which the over-recoveries took place, and the refund period represents the billing month in which customers received the refund amounts shown, including interest: Docket No. Date Filed Date Approved Recovery Period Refund Period Refund Amount Authorized (In Thousands) 40622 August 3, 2012 September 28, 2012 January 2011- June 2012 September 2012 $ 6,600 The Company filed the following petitions with the PUCT to revise its fixed fuel factor pursuant to the fuel factor formula authorized in PUCT Docket No. 37690: Docket No. 40302 41803 Date Filed April 12, 2012 Date Approved April 25, 2012 September 9, 2013 September 23, 2013 Increase (Decrease) in Fuel Factor (18.5)% 12.2% Effective Billing Month May 2012 October 2013 Fuel Reconciliation Proceeding. On September 27, 2013, the Company filed an application with the PUCT, designated as Docket No. 41852, to reconcile $545.3 million of fuel and purchased power expenses incurred during the 45-month period from July 1, 2009 through March 31, 2013. The fuel reconciliation requests to recover $3.4 million of rewards for Palo Verde operations. Intervenor testimony is due February 28, 2014 and PUCT Staff testimony is due March 7, 2014. Hearings in the fuel reconciliation are scheduled to begin March 31, 2014 and a final order must be issued by September 26, 2014. Montana Power Station Approvals. The Company has received a Certificate of Convenience and Necessity ("CCN") authorization from the PUCT to construct the first two (of four) units of the Montana Power Station ("the MPS"). The Company must also obtain air permits from state and federal regulatory agencies before it can begin construction. On January 22, 2014, the Texas Commission on Environmental Quality ("TCEQ") issued the required permit. The U.S. Environmental Protection Agency ("EPA") issued a draft permit for greenhouse gas ("GHG") in September 2013 and solicited public comment. EPA is considering comments filed in response to that proposal before issuing a final permit. The Company believes that the type of facility planned 57 Table of Contents EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS at the MPS complies with all EPA regulations for granting a GHG permit and that the issues raised in the comments have previously been resolved in proceedings in other regions in favor of the grant of a permit. If the permit is granted, commenters may challenge the determination before the U.S. EPA’s Environmental Appeals Board. While the Company believes that this application demonstrates compliance with all applicable regulations, it cannot predict the timing or final outcome. On September 6, 2013, the Company filed an application with the PUCT for issuance of a CCN to construct, own and operate two additional 88 MW natural gas-fired generating units designated as the MPS Units 3 and 4 in El Paso County, Texas. The case has been designated PUCT Docket No. 41763. Hearings in this case were held in February 2014. In accordance with PUCT rules, the final order must be issued by September 5, 2014. The Company filed three transmission line CCN applications with the PUCT as part of the MPS Project: • MPS to Caliente: a 115-kV transmission line from the MPS to the existing Caliente Substation in east El Paso. (PUCT Docket No. 41360) • MPS In & Out: a 115-kV transmission line from the MPS to intersect with the existing Caliente - Coyote 115-kV transmission line. (PUCT Docket No. 41359) • MPS to Montwood: a 115-kV transmission line from the MPS to the existing Montwood Substation in east El Paso. (PUCT Docket No. 41809) The transmission CCN filings for both the MPS to Caliente and the MPS In & Out were filed on April 15, 2013, and the transmission CCN filing for the MPS to Montwood was filed on September 24, 2013. The Company is requesting to build these transmission lines to connect the new MPS to the electrical grid in order to meet increased customer growth and electric demand and to improve system reliability. A final order approving a unanimous settlement in the MPS to Caliente transmission CCN filing is expected by the end of the first quarter of 2014. Final orders in the transmission CCN filings for the MPS In & Out and the MPS to Montwood filings are expected no later than October 2014. Other Required Approvals. The Company has obtained other required approvals for recovery of fuel costs through fixed fuel factors, other tariffs and approvals as required by the Public Utility Regulatory Act ( the "PURA") and the PUCT. New Mexico Regulatory Matters 2009 New Mexico Stipulation. On December 10, 2009, the NMPRC issued a final order conditionally approving the stipulated rates in NMPRC Case No. 09-00171-UT. The stipulated rates went into effect with January 2010 bills. The stipulated rates provide for an Efficient Use of Energy Factor Rate Rider to recover energy efficiency expenditures which requires an annual filing and approval of the related incentives and adjustment to the recovery factors. Fuel and purchased power costs in New Mexico are recovered through a Fuel and Purchased Power Cost Recovery Factor (the "FPPCAC"). On January 8, 2014, the NMPRC approved the continuation of the FPPCAC without modification. The Company recovers its investment in Palo Verde Unit 3 in New Mexico through the FPPCAC as purchased power using a proxy market price approved in the 2009 New Mexico rate stipulation. 2013 Annual Procurement Plan Pursuant to the Renewable Energy Act. On July 1, 2013, the Company filed its application for approval of its 2013 Annual Procurement Plan pursuant to the New Mexico Renewable Energy Act. On November 20, 2013, the NMPRC issued a final order approving the renewable procurement plan with modifications recommended by the Hearing Examiner. The plan sets out the Company's procurement of renewable resources and estimated costs for 2014 and 2015 to meet Renewable Portfolio Standards ("RPS") and resource diversity requirements. The approved plan provides for the RPS and diversity requirements for 2014 and 2015 to be met with a combination of previously approved resources and grants the Company's request for waiver for meeting the full RPS through 2015 due to reasonable cost threshold limits. The order also grants the Company's requested diversity variances for 2014 and 2015. Costs for purchases of renewable energy delivered to the Company are recovered through the FPPCAC and purchases of unbundled renewable energy credits are recovered through base rates. Long-Term Purchased Power Agreement with Macho Springs. On November 21, 2012, the Company filed an application with the NMPRC requesting approval of a Long-Term Purchase Power Agreement (the "LTPPA") with Macho Springs Solar, LLC ("Macho Springs") to purchase energy from a 50 MW solar facility to be constructed by Macho Springs on the Company's New Mexico transmission system. The Company also sought approval of the recovery of costs associated with the LTPPA through the Company's FPPCAC. A final order approving the LTPPA and recovery through the FPPCAC was received May 1, 2013. 58 Table of Contents EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS Montana Power Station Approvals. The Company has received a CCN authorization from the NMPRC to construct the first two (of four) units of the MPS. As discussed above, the Company must also obtain air permits from the TCEQ and EPA before it can begin construction. On September 6, 2013, the Company filed an application with the NMPRC for issuance of a CCN to construct, own and operate two additional 88 MW natural gas-fired generating units designated as the MPS Units 3 and 4 in El Paso County, Texas. The case has been designated NMPRC Case No. 13-00297-UT. No protests to the Company's application were filed and the hearing examiner issued a recommended decision to approve the Company's application on February 20, 2014. A final order is expected in the first quarter of 2014. Revolving Credit Facility, Issuance of Long-Term Debt and Guarantee of Debt. On October 30, 2013, the Company received approval in NMPRC Case No. 13-00317-UT to amend its current $300 million Revolving Credit Facility ("RCF") to include an option, subject to lender's approval, to expand the amount of the potential borrowings available under the facility to $400 million and extend the maturity date by up to four years; issue up to $300 million in new long-term debt; and to guarantee the issuance of up to $50 million of new debt by Rio Grande Resources Trust ("RGRT") to finance future purchases of nuclear fuel and to refinance existing debt obligations related to the financing of purchases of nuclear fuel. 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. Under the terms of the agreement, the Company has available $300 million and the ability to increase the RCF by up to $100 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 has a term ending January 2019. The Company may extend the maturity date up to two times, in each case for an additional one year period upon the satisfaction of certain conditions. Other Required Approvals. The Company has obtained other required approvals for other tariffs, securities transactions, long-term resource plans, recovery of energy efficiency costs through a base rate rider and other approvals as required by the NMPRC. Federal Regulatory Matters Public Service Company of New Mexico's ("PNM") 2010 Transmission Rate Case. On October 27, 2010, PNM filed a Notice of Transmission Rate Change for transmission delivery services provided by PNM. These rates went into effect on June 1, 2011. The Company takes transmission service from PNM. On January 2, 2013, the FERC issued a letter order approving a unanimous stipulation and agreement. Pursuant to the stipulation, on January 31, 2013, PNM refunded $1.9 million for amounts that PNM collected since June 1, 2011 in excess of settlement rates. This amount was recorded in the fourth quarter of 2012 as a reduction of transmission expense. Revolving Credit Facility, Issuance of Long-Term Debt and Guarantee of Debt. On September 30, 2013, the Company filed an application for approval to amend its current $300 million RCF to include an option, subject to lender's approval, to expand the amount of the potential borrowings available under the facility to $400 million and extend the maturity date by up to four years; issue up to $300 million in new long-term debt; and to guarantee the issuance of up to $50 million of new debt by RGRT to finance future purchases of nuclear fuel and to refinance existing debt obligations related to the purchase of nuclear fuel. The FERC issued an order approving the filing on November 15, 2013. The case was assigned to FERC Docket No. ES 13-59-000. As noted above, on January 14, 2014, the Company and RGRT entered into a second amended and restated credit agreement related to the RCF. Other Required Approvals. The Company has obtained required approvals for rates and tariffs, securities transactions and other approvals as required by the FERC. Department of Energy ("DOE"). The DOE regulates the Company's exports of power to the Comision Federal de Electricidad in Mexico pursuant to a license granted by the DOE and a presidential permit. The DOE is authorized to assess operators of nuclear generating facilities a share of the costs of decommissioning the DOE's uranium enrichment facilities and for the ultimate costs of disposal of spent nuclear fuel. See Note E for discussion of spent fuel storage and disposal costs. 59 Table of Contents Sales for Resale EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS The Company provides firm capacity and associated energy to the RGEC pursuant to an ongoing contract with a two- year notice to terminate provision. The Company also provides network integrated transmission service to the RGEC pursuant to the Company's 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. 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 sheets are presented below (in thousands): Amortization Period Ends December 31, 2013 December 31, 2012 Regulatory assets Regulatory tax assets (a) ........................................................ Loss on reacquired debt (c) .................................................... May 2035 Final coal reclamation (f) ....................................................... July 2016 (b) Nuclear fuel postload daily financing charge......................... Unrecovered issuance costs due to reissuance of PCBs (c) ... August 2042 Texas energy efficiency.......................................................... (d) (e) Texas 2012 rate case costs (f)................................................. April 2014 Texas military base discount and recovery factor .................. New Mexico procurement plan costs ..................................... New Mexico renewable energy credits .................................. New Mexico 2010 FPPCAC audit ......................................... New Mexico Palo Verde deferred depreciation...................... Total regulatory assets Regulatory liabilities Regulatory tax liabilities (a) ................................................... Accumulated deferred investment tax credit (i) ..................... New Mexico energy efficiency .............................................. Texas energy efficiency.......................................................... Total regulatory liabilities (h) (g) (g) (g) (b) (b) (b) (e) (e) $ $ $ $ 61,772 $ 18,338 4,290 4,141 893 — 581 759 139 4,833 433 4,871 101,050 17,752 4,656 3,646 362 $ $ 26,416 $ 57,551 19,191 5,473 3,833 926 536 2,335 2,116 139 4,033 433 5,024 101,590 16,666 4,587 926 — 22,179 ________________ (a) No specific return on investment is required since related assets and liabilities offset. (b) The amortization period for this asset is 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 is recovered through fuel recovery mechanisms. (e) This item is recovered or credited through a recovery factor that is set annually. (f) This item is included in rate base which earns a return on investment. (g) Amortization period is anticipated to be established in next general rate case. (h) This item represents the net asset related to the military discount which is recovered from non-military customers through a recovery factor. (i) This item is excluded from rate base. 60 Table of Contents 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, 2013 (in thousands): Nuclear production ....................................................................... $ Steam and other ............................................................................ Total production .................................................................... Transmission ................................................................................ Distribution................................................................................... General ......................................................................................... Intangible...................................................................................... Gross Plant 817,665 668,666 1,486,331 432,674 965,674 122,209 69,661 Total....................................................................................... $ 3,076,549 $ Accumulated Depreciation Net Plant 546,492 404,647 951,139 186,499 628,161 63,978 32,684 $ (1,214,088) $ 1,862,461 (271,173) $ (264,019) (535,192) (246,175) (337,513) (58,231) (36,977) Amortization of intangible plant (software) is provided on a straight-line basis over the estimated useful life of the asset (ranging from 5 to 10 years). The table below presents the actual and estimated amortization expense for intangible plant for the previous three years and for the next five years (in thousands): 2011 ..................................................................................... $ 2012 ..................................................................................... 2013 ..................................................................................... 2014 (estimated) .................................................................. 2015 (estimated) .................................................................. 2016 (estimated) .................................................................. 2017 (estimated) .................................................................. 2018 (estimated) .................................................................. 6,668 7,183 7,683 7,372 6,540 5,980 5,326 3,713 The Company owns a 15.8% interest in each of the three nuclear generating units and common facilities at Palo Verde, in Wintersburg, Arizona. The Palo Verde Participants include the Company and six other utilities: Arizona Public Service Company ("APS"), Southern California Edison Company ("SCE"), Public Service Company of New Mexico ("PNM"), Southern California Public Power Authority, Salt River Project Agricultural Improvement and Power District ("SRP") and the Los Angeles Department of Water and Power. Other jointly-owned utility plant includes a 7% interest in Units 4 and 5 at Four Corners Generating Station ("Four Corners") and certain other transmission facilities. A summary of the Company’s investment in jointly-owned utility plant, excluding fuel inventories, at December 31, 2013 and 2012 is as follows (in thousands): Electric plant in service ............................................................... $ Accumulated depreciation ........................................................... Construction work in progress..................................................... Total...................................................................................... $ December 31, 2013 December 31, 2012 Palo Verde 817,665 (271,173) 75,040 621,532 $ $ Other 217,137 (173,819) 2,347 45,665 $ $ Palo Verde 795,259 (257,540) 64,623 602,342 $ $ Other 213,155 (168,569) 2,401 46,987 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. 61 Table of Contents EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS 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. NRC. The NRC regulates the operation of all commercial nuclear power reactors in the United States, including Palo Verde. The NRC periodically conducts inspections of nuclear facilities and monitors performance indicators to enable the agency to arrive at objective conclusions about a licensee’s safety performance. License Extension. On April 21, 2011, the Company, along with the other Palo Verde Participants, was notified that the NRC had renewed the operating licenses for all three units at Palo Verde. The renewed licenses for Units 1, 2 and 3 now expire in 2045, 2046 and 2047, respectively. Decommissioning. Pursuant to the ANPP Participation Agreement and federal law, the Company must fund its share of the estimated costs to decommission Palo Verde Units 1, 2 and 3, including the Common Facilities, through the term of their respective operating licenses and is required to maintain a minimum accumulation and funding level in its decommissioning account at the end of each annual reporting period during the life of the plant. The Company has established external trusts with an independent trustee, which enables the Company to record a current deduction for federal income tax purposes for most of the amounts funded. At December 31, 2013, the Company’s decommissioning trust fund had a balance of $214.1 million, which is above its minimum funding level. The Company monitors the status of its decommissioning funds and adjust its deposits, if necessary. Decommissioning costs are estimated every three years based upon engineering cost studies performed by outside engineers retained by APS. 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 asset retirement obligation by $1.9 million and will lower 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 significant uncertainty. 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. APS (on behalf of itself and the other Palo Verde participants) filed a lawsuit for DOE's breach of the spent nuclear fuel contract in the U.S. Court of Federal Claims. The Court of Federal Claims ruled in favor of APS and in October 2010 awarded $30.0 million in damages to the Palo Verde participants for costs incurred through December 2006. In October 2010, the Company received $4.8 million, representing its share of the award. The majority of the award was refunded to customers through the applicable fuel adjustment clauses. On December 19, 2012, APS, acting on behalf of itself and the participant owners of Palo Verde, filed a second breach of contract lawsuit against the DOE. This lawsuit seeks to recover damages incurred due to DOE's failure to accept Palo Verde's spent nuclear fuel for the period beginning January 1, 2007 through June 30, 2011.The lawsuit is presently pending in the Court of Federal Claims. The DOE had planned to meet its disposal obligations by designing, licensing, constructing, and operating a permanent geologic repository at Yucca Mountain, Nevada. In March 2010, the DOE filed a motion to dismiss with prejudice its Yucca Mountain construction authorization application that was pending before the NRC. Several interested parties have intervened in the NRC proceeding, and the proceeding has not been conclusively decided by the NRC or the courts. Additionally, a number of interested parties have filed a variety of lawsuits in different jurisdictions around the country challenging the DOE's authority to withdraw the Yucca Mountain construction authorization application and NRC’s cessation of its review of the Yucca Mountain construction authorization application. The cases have been consolidated into one matter at the D.C. Circuit. In August 2013, the 62 Table of Contents EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS D.C. Circuit ordered the NRC to resume its review of the application with available appropriated funds. The Company cannot predict when spent fuel shipments to the DOE will commence. APS and the Company believe that spent fuel storage or disposal methods will be available to allow each Palo Verde unit to continue to operate through the current term of its operating license. The Company expects to incur significant costs for on-site spent fuel storage during the life of Palo Verde which the Company believes are the responsibility of the DOE. These costs are assigned to fuel requiring the additional on-site storage and amortized as that fuel is burned until an agreement is reached with the DOE for recovery of these costs. The One-Mill Fee. In 2011, the National Association of Regulatory Utility Commissioners and the Nuclear Energy Institute challenged DOE’s 2010 determination of the adequacy of the one tenth of a cent per kWh 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 is recovered by the Company through applicable fuel adjustment clauses. In June 2012, the U.S. Court of Appeals for the District of Columbia Circuit (the "D.C. Circuit") held that 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 ("Secretary") with instructions to conduct a new fee adequacy determination within six months. In February 2013, upon completion of 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. 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. Due to the developing nature of these requirements, the Company cannot predict the ultimate financial or operational impacts on Palo Verde or the Company; however, the NRC has directed nuclear power plants to implement the first tier recommendations of the NRC’s Near Term Task Force. In response to these recommendations, Palo Verde expects to spend approximately $100 million for capital enhancements to the plant over the next several years (the Company's share is $15.8 million). Liability and Insurance Matters. The Palo Verde participants have insurance for public liability resulting from nuclear energy hazards to the full limit of liability under federal law, which is currently at $13.6 billion. This potential liability is covered by primary liability insurance provided by commercial insurance carriers in the amount of $375 million, and the balance is covered by an industry-wide retrospective assessment program. If a loss at a nuclear power plant covered by the programs exceeds the accumulated funds in the primary level of protection, the Company could be assessed retrospective premium adjustments on a per incident basis. Under federal law, the maximum assessment per reactor under the program for each nuclear incident is approximately $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 "all risk" (including nuclear hazards) insurance for property damage to, and decontamination of, property at Palo Verde in the aggregate amount of $2.8 billion, a substantial portion of which must first be applied to stabilization and decontamination. The Company has also secured insurance against portions of any increased cost of generation or purchased power and business interruption resulting from a sudden and unforeseen outage of any of the three units. The insurance coverage discussed in this and the previous paragraph is subject to certain policy conditions and exclusions. A mutual insurance company whose members are utilities with nuclear facilities issues these policies. If losses at any nuclear facility covered by this mutual insurance company were to exceed the accumulated funds for these insurance programs, the Company could be assessed retrospective premium adjustments of up to $9.8 million for the current policy period. 63 Table of Contents Four Corners EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS The Company owns a 7% interest in Units 4 and 5 at Four Corners. The Company shares power entitlements and certain allocated costs of the two units with APS (the Four Corners operating agent) and the other Four Corners participants. The 50-year participation agreement among the owners of Four Corners expires by its terms in July 2016. The Company has notified the other owners that it has decided to cease its participation in the plant by July 2016. The Company believes that it has better economic and cleaner alternatives for serving the energy needs of its customers than coal-fired generation. The Company has nevertheless agreed to work with the other owners and the Navajo Nation in an attempt to facilitate their efforts to extend the operation of the plant beyond July 2016 in a manner consistent with protecting the Company's ratepayers. In December 2013, the other owners executed a long-term extension of the coal supply agreement for the plant through 2031. The Company did not sign the extension and APS has agreed to assume the resulting 7% shortfall and has also expressed an interest in acquiring the Company’s interest in Four Corners. F. Accounting for Asset Retirement Obligations The Company complies with FASB guidance for asset retirement obligations ("ARO"). This guidance affects the accounting for the decommissioning of the Company’s Palo Verde and Four Corners Stations and the method used to report the decommissioning obligation. The Company also complies with FASB guidance for conditional asset retirement obligations which primarily affects the accounting for the disposal obligations of the Company’s fuel oil storage tanks, water wells, evaporative ponds and asbestos found at the Company’s gas-fired generating plants. The Company’s AROs are subject to various assumptions and determinations such as: (i) whether a legal obligation exists to remove assets; (ii) estimation of the fair value of the costs of removal; (iii) when final removal will occur; (iv) future changes in decommissioning cost escalation rates; and (v) the credit- adjusted interest rates to be utilized in discounting future liabilities. Changes that may arise over time with regard to these assumptions and determinations will change amounts recorded in the future as an expense for AROs. The Company records the increase in the ARO due to the passage of time as an operating expense (accretion expense). If the Company incurs or assumes 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 2013 ARO liability for Palo Verde is based upon the estimated cost of decommissioning the plant from the 2013 Palo Verde decommissioning study. See Note E. The ARO liability is calculated by adjusting the estimated decommissioning costs for spent fuel storage and a profit margin and market-risk premium factor. The resulting costs are escalated over the remaining life of the plant and finally discounted using a credit-risk adjusted discount rate. As Palo Verde approaches the end of its estimated useful life, the difference between the ARO liability and future current cost estimates will narrow over time due to the accretion of the ARO liability. Because the DOE is obligated to assume responsibility for the permanent disposal of spent fuel, spent fuel costs have not been included in the ARO calculation. The Company 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, 2013 is $214.1 million. FASB guidance requires the Company to revise its previously recorded ARO for any changes in estimated cash flows including changes in estimated probabilities related to timing of settlements. Any changes that result in an upward revision to estimated cash flows shall be treated as a new liability. Any downward revisions to the estimated cash flows result in a reduction to the previously recorded ARO. In 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 Note E). The assumptions used to calculate the Palo Verde ARO liability are as follows: Original ARO liability............... Incremental ARO liability......... Escalation Rate 3.60% 3.60% Credit-Risk Adjusted Discount Rate 9.50% 6.20% A roll forward of the Company’s total ARO liability from January 1, 2011 through December 31, 2013, including the effects of each year’s estimate revisions, is presented below. In 2013, the estimate revision includes a change to the probability of extending Four Corners’ operating term and decreases in the estimated cash flows related to Palo Verde’s decommissioning due to implementing the 2013 Palo Verde decommissioning study. In 2012, the estimate revision includes a change to the probability of 64 Table of Contents EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS extending Four Corners’ operating term. In 2011, the NRC approved the Palo Verde license extension which increased Palo Verde decommissioning estimated cash flows and the related probabilities for life extension in the Company’s ARO calculation. ARO liability at beginning of year........................ $ Liabilities incurred ......................................... Liabilities settled............................................ Revisions to estimate ..................................... Accretion expense.......................................... ARO liability at end of year .................................. $ 2013 62,784 — (36) (3,401) 5,867 65,214 $ $ 2012 56,140 — (450) 1,929 5,165 62,784 $ $ 2011 92,911 — (793) (41,670) 5,692 56,140 The Company has transmission and distribution lines which are operated under various property easement agreements. If the easements were to be released, the Company may have a legal obligation to remove the lines; however, the Company has assessed the likelihood of this occurring as remote. The majority of these easements include renewal options which the Company routinely exercises. G. Common Stock Overview The Company’s common stock has a stated value of $1 per share, with no cumulative voting rights or preemptive rights. Holders of the common stock have the right to elect the Company’s directors and to vote on other matters. Long-Term Incentive Plan On May 2, 2007, the Company’s shareholders approved a stock-based long-term incentive plan (the "2007 LTIP") and authorized the issuance of up to one million shares of common stock for the benefit of directors and employees. Under the 2007 LTIP, common stock may be issued through the award or grant of non-statutory stock options, incentive stock options, stock appreciation rights, restricted stock, bonus stock, performance stock, cash-based awards and other stock-based awards. The Company may issue new shares, purchase shares on the open market, or issue shares from shares the Company has repurchased to meet the share requirements of the 2007 LTIP. As discussed in Note A, the Company accounts for its stock-based long-term incentive plan under FASB guidance for stock-based compensation. Stock Options. Stock options have been granted at exercise prices equal to or greater than the market value of the underlying shares at the date of grant. The fair value for these options was estimated at the grant date using the Black-Scholes option pricing model. The options expired ten years from the date of grant unless terminated earlier by the Board of Directors (the “Board”). Stock options have not been granted since 2003. The 15,000 options outstanding at December 31, 2012 were exercised during 2013 with a weighted average exercise price of $12.78. The Company received $0.2 million in cash and realized a current tax benefit of $0.1 million. The Company has no stock options outstanding as of December 31, 2013. The intrinsic value of stock options exercised in 2013, 2012 and 2011 were $0.3 million, $0.6 million and $1.0 million, respectively. No options were forfeited, vested or expired during 2013, 2012 and 2011. No compensation cost was recognized in 2013, 2012 and 2011 for stock options. Restricted Stock. The Company has awarded restricted stock under its long-term incentive plan. Restrictions from resale generally lapse and awards vest over periods of one to three years. The market value of the unvested restricted stock at the date of grant is amortized to expense over the restriction period net of anticipated forfeitures. 65 Table of Contents EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS The expense, deferred tax benefit, and current tax expense recognized related to restricted stock awards in 2013, 2012 and 2011 is presented below (in thousands): 2013 2012 2011 Expense (a)....................................... Deferred tax benefit ......................... Current tax benefit recognized......... _____________________ (a) Any capitalized costs related to these expenses is less than $0.1 million for all years. 1,508 2,458 860 109 528 94 $ $ $ 2,258 790 518 The aggregate intrinsic value and fair value at grant date of restricted stock which vested in 2013, 2012 and 2011 is presented below (in thousands): 2013 2012 2011 Aggregated intrinsic value........... Fair value at grant date ................ $ $ 2,077 1,765 $ 2,242 1,973 3,279 1,799 The unvested restricted stock transactions for 2013 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, 2012 ..... 84,446 $ Restricted stock awards ........................................... Vested ...................................................................... Forfeitures................................................................ Restricted shares outstanding at December 31, 2013 ..... 96,279 (58,642) (1,549) 120,534 31.26 35.48 30.10 31.28 35.19 $ 1,976 $ 4,232 _______________________ (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 awarded during 2013, 2012 and 2011 were: Weighted average fair value per share ............ $ 35.48 $ 32.45 $ 28.98 2013 2012 2011 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. 66 Table of Contents EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS Performance Shares. The Company has granted performance share awards to certain officers under the Company’s existing long-term incentive plan, which provides for issuance of Company stock based on the achievement of certain performance criteria over a three-year period. The payout varies between 0% to 200% of performance share awards. Detail of performance shares vested follows: Date Vested Payout Ratio Performance Shares Awarded Compensation Costs Expensed (In thousands) February 18, 2014 0% 0 $ January 29, 2013 150.0% 64,275 954 849 Period Compensation Costs Expensed Aggregated Intrinsic Value (In thousands) 2011-2013 $ — 2010-2012 January 1, 2012 175.0% 174,038 1,193 2009-2011 September 3, 2011 112.5% July 9, 2011 112.5% 3,825 2,250 40 23 2008-2011 2008-2011 2,176 6,029 129 75 In 2014, 2015 and 2016, subject to meeting certain performance criteria, additional performance shares could be awarded. In accordance with FASB guidance related to stock-based compensation, the Company recognizes the related compensation expense by ratably amortizing the grant date fair value of awards over the requisite service period and the compensation expense is only adjusted for forfeitures. The actual number of shares to be issued can range from zero to 181,894 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 (a) Aggregate Intrinsic Value (In thousands) (In thousands) Performance shares outstanding at December 31, 2012... 128,033 $ Performance share awards ................................................ Performance shares vested................................................ Performance shares outstanding at December 31, 2013... 39,814 (42,850) 124,997 26.48 34.69 19.82 31.38 $ 1,452 $ 4,389 _______________________ (a) The unrecognized compensation expense is expected to be recognized over the weighted average remaining contractual term of the awards of approximately one year. 67 Table of Contents EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS A summary of information related to performance shares for 2013, 2012 and 2011 is presented below: 2013 2012 2011 Weighted average per share grant date fair value per share of performance shares awarded ....................................................................... $ Fair value of performance shares vested (in thousands) ............................. Intrinsic value of performance shares vested (in thousands) (a) ................. Compensation expense (in thousands) (b)................................................... Deferred tax benefit related to compensation expense (in thousands) ........ 34.69 $ 849 1,450 1,188 416 32.74 1,193 3,464 170 59 $ 23.45 628 1,032 1,573 551 _____________________ (a) Based on a 100% performance level. (b) Includes adjustments for forfeiture of performance share awards by certain executives. Repurchase Program No shares of common stock were repurchased during the twelve months ended December 31, 2013. Detail regarding the Company's stock repurchase program are presented below: Shares repurchased (b) ................................................................................ Cost, including commission (in thousands) ................................................ $ Total remaining shares available for repurchase at December 31, 2013..... Since 1999 (a) 25,406,184 423,647 Authorized Shares 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. The Company may in the future make purchases of its common stock pursuant to its authorized program in open market transactions at prevailing prices and may engage in private transactions where appropriate. The repurchased shares will be available for issuance under employee benefit and stock incentive plans, or may be retired. Dividend Policy On December 30, 2013, the Company paid $10.7 million in quarterly cash dividends to shareholders. The Company paid a total of $42.0 million, $38.9 million and $27.2 million in cash dividends during the twelve months ended December 31, 2013, 2012 and 2011, respectively. On January 23, 2014, the Board of Directors declared a quarterly cash dividend of $0.265 per share payable on March 31, 2014 to shareholders of record on March 14, 2014. 68 Table of Contents EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS Basic and Diluted Earnings Per Share FASB guidance requires the Company to include share-based compensation awards that qualify as participating securities in both basic and diluted earnings per share to the extent they are dilutive. A share-based compensation award is considered a participating security if it receives non-forfeitable dividends or may participate in undistributed earnings with common stock. The Company awards unvested restricted stock which qualifies as a participating security. The basic and diluted earnings per share are presented below: Years Ended December 31, 2012 2011 2013 Weighted average number of common shares outstanding: Basic number of common shares outstanding ............................................... Dilutive effect of unvested performance awards ................................... Dilutive effect of stock options .............................................................. Diluted number of common shares outstanding ............................................ 40,114,594 12,053 — 40,126,647 39,974,022 66,756 14,803 40,055,581 41,349,883 206,658 30,518 41,587,059 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 ................................................... $ 88,583 (254) 88,329 88,583 (254) 88,329 1.045 1.155 2.200 1.045 1.155 2.200 $ $ $ $ $ $ $ $ 90,846 (256) 90,590 90,846 (256) 90,590 0.97 1.30 2.27 0.97 1.29 2.26 $ $ $ $ $ $ $ $ 103,539 (471) 103,068 103,539 (469) 103,070 0.66 1.83 2.49 0.66 1.82 2.48 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 ............................................ Year Ended December 31, 2012 45,178 2013 51,189 Performance shares (a) ............................................. 115,044 57,625 2011 81,653 — _____________________ (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. 69 Table of Contents 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 which are presented below (in thousands): Years Ended December 31, 2013 Unrecognized Pension and Postretirement Benefit Costs Net Unrealized Gains (Losses) on Marketable Securities Net Losses on Cash Flow Hedges Accumulated Other Comprehensive Income (Loss) Balance at December 31, 2012............................ $ (75,737) $ 22,194 $ (12,541) $ (66,084) Other comprehensive income before reclassifications.......................................... Amounts reclassified from accumulated other comprehensive income (loss)................... Balance at December 31, 2013............................ $ 51,371 14,482 — 65,853 3,036 (21,330) $ (436) 36,240 $ 243 (12,298) $ 2,843 2,612 70 Table of Contents EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS Amounts reclassified from accumulated other comprehensive income (loss) for the twelve months ended December 31, 2013 are as follows ( in thousands): Details about Accumulated Other Comprehensive Income (Loss) Components 2013 Affected Line Item in the Statement of Operations Amortization of pension and postretirement benefit costs: Prior service benefit ............................................... Net loss................................................................... $ Income tax effect .................................................... 5,560 (10,472) (4,912) 1,876 (3,036) (a) (a) (a) (a) Marketable securities: Net realized gain on sale of securities .................... 553 Investment and interest income, net Income before income taxes 553 (117) 436 Net income Income tax expense Loss on cash flow hedge: Amortization of loss ............................................... (411) Interest on long-term debt and revolving credit facility Income before income taxes (411) 168 (243) Net income Income tax expense Total reclassifications............................................. $ (2,843) (a) These items are included in the computation of net periodic benefit cost. See Note M, Employee Benefits, for additional information. 71 Table of Contents 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 (1): 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 (2): 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)............... Total Senior Notes................................................................................................... RGRT Senior Notes (3): 3.67% Senior Notes, Series A, due 2015 (3.87% effective interest rate)......................... 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....................................................................................... December 31, 2013 2012 (In thousands) $ 63,500 59,235 37,100 33,300 193,135 397,976 148,800 149,709 696,485 15,000 50,000 45,000 110,000 999,620 63,500 59,235 37,100 33,300 193,135 397,934 148,783 149,683 696,400 15,000 50,000 45,000 110,000 999,535 Financing Obligations: Revolving Credit Facility ($14,352 due in 2014) (4) .............................................................. Total long-term debt and financing obligations...................................................... 14,352 1,013,972 22,155 1,021,690 Current Portion (amount due within one year): Short-term borrowings under the revolving credit facility............................................... (14,352) 999,620 $ (22,155) 999,535 $ _____________________ (1) 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. (2) Senior Notes The Senior Notes are unsecured obligations of the Company. They were issued pursuant to bond covenants that provide limitations on the Company’s ability to enter into certain transactions. The 6.00% senior notes have an aggregate principal amount of $400.0 million and were issued in May 2005. The proceeds, net of a $2.3 million discount, were used to fund the retirement of the Company's first mortgage bonds. The Company amortizes the loss associated with a cash flow hedge recorded in accumulated other comprehensive income to earnings as interest expense over the life of the 6.00% senior notes. See Note O, "Financial Instruments and Investments - Treasury Rate Locks". This amortization is included in the effective interest rate of the 6.00% senior notes. The 7.50% senior notes have an aggregate principal amount of $150.0 million and were issued in June 2008. The proceeds, net of a $1.3 million discount, were used to repay short-term borrowings of $44.0 million, fund capital expenditures and for other general corporate purposes. 72 Table of Contents EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS The 3.30% senior notes have an aggregate principal amount of $150.0 million and 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. (3) RGRT Senior Notes In 2010, the Company and RGRT, a Texas grantor trust through which the Company finances its portion of fuel for Palo Verde, entered into a note purchase agreement with various institutional purchasers. Under the terms of the Agreement, RGRT sold to the purchasers $110 million aggregate principal amount of senior notes (the "Notes"). The Company guarantees the payment of principal and interest on the Notes. In the Company’s financial statements, the assets and liabilities of the RGRT are reported as assets and liabilities of the Company. RGRT will pay interest on the Notes on February 15, and August 15 of each year until maturity. RGRT may redeem the Notes, in whole or in part, at any time at a redemption price equal to 100% of the principal amount to be redeemed together with the interest on such principal amount accrued to the date of redemption, plus a make-whole amount based on the prevailing market interest rates. The agreement requires compliance with certain covenants, including a total debt to capitalization ratio. The Company was in compliance with these requirements throughout 2013. The sale of the Notes was made by RGRT in reliance on a private placement exemption from registration under the Securities Act of 1933, as amended. The proceeds of $109.4 million, net of issuance costs, from the sale of the Notes was used by RGRT to repay amounts borrowed under the revolving credit facility and will enable future nuclear fuel financing requirements of RGRT to be met with a combination of the Notes and amounts borrowed from the revolving credit facility. (4) Revolving Credit Facility On 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. Under the terms of the agreement, the Company has available $300 million and the ability to increase the RCF by up to $100 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 has a term ending January 2019. The Company may extend the maturity date up to two times, in each case for an additional one year period upon the satisfaction of certain conditions. 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 with certain covenants, including a total debt to capitalization ratio. The Company was in compliance with these requirements throughout 2013. As of December 31, 2013, the total amount borrowed by RGRT was $14.4 million for nuclear fuel under the RCF. As of December 31, 2013, no borrowings were outstanding under this facility for working capital and general corporate purposes. The weighted average interest rate on the RCF was 1.4% as of December 31, 2013. As of December 31, 2013, the scheduled maturities for the next five years of long-term debt are as follows (in thousands): 2014....................................................... $ 2015....................................................... 2016....................................................... 2017....................................................... 2018....................................................... — 15,000 — 83,300 — The $14.4 million outstanding on the RCF for nuclear fuel financing purposes is anticipated to be paid in 2014. 73 Table of Contents J. Income Taxes EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and liabilities at December 31, 2013 and 2012 are presented below (in thousands): December 31, 2013 2012 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.......................................................................................... $ 17,709 21,638 54,652 23,727 — 14,485 132,211 7,798 21,599 86,816 21,710 1,951 14,115 153,989 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 ................................................................. $ (511,847) (35,489) (2,171) (5,664) (555,171) (422,960) $ (457,127) (29,416) — (5,828) (492,371) (338,382) Based on the average annual book income before taxes for the prior three years, excluding the effects of extraordinary and unusual or infrequent items, the Company believes that the deferred tax assets will be fully realized at current levels of book and taxable income. The Company recognized income tax expense for 2013, 2012 and 2011 as follows (in thousands): Years Ended December 31, 2013 2012 2011 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............................................................... $ (2,877) $ 45,024 42,147 1,854 (414) 1,440 68 43,655 $ 1,487 43,187 44,674 1,931 697 2,628 (323) 46,979 $ $ 5,084 46,864 51,948 2,936 (924) 2,012 (252) 53,708 As of December 31, 2013, the Company had $21.6 million of AMT credit carryforwards that have an unlimited life. As of December 31, 2013, the Company had $17.3 million of federal and $0.4 million of state tax loss carryforwards. If unused, the tax loss carryforwards would expire at the end of 2031 through 2033 and 2016 through 2018, for federal and state, respectively. 74 Table of Contents EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS 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............................................................... $ Years Ended December 31, 2013 46,283 2012 48,239 $ 2011 55,036 $ 936 (2,149) (1,153) (262) 43,655 $ 1,708 (1,845) (604) (519) 46,979 $ 1,308 (2,295) (303) (38) 53,708 Effective income tax rate ...................................................................................... 33.0% 34.1% 34.2% The Company files income tax returns in the United State ("U.S.") federal jurisdiction and in the states of Texas, New Mexico and Arizona. The Company is no longer subject to tax examination by the taxing authorities in the federal jurisdiction for years prior to 2009 and in New Mexico for years prior to 2009. The Company is currently under audit in Texas for tax years 2007 through 2011. A deficiency notice relating to the Company’s 1998 through 2003 and 2006 and 2007 income tax returns in Arizona challenges a pollution control credit, a research and development credit and the payroll, sales and property apportionment factors. The Company is contesting these adjustments. FASB guidance prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. In January 2010, the Company filed for a change of accounting method with the IRS related to the way in which units of property are determined for purposes of determining capitalized tax assets. The change was included in the 2009 federal income tax return, with additional amounts included in the 2010 to 2012 federal income tax returns. The Company recorded an additional unrecognized tax position of $1.6 million and $2.2 million in 2012 and 2011, respectively, related to the change in accounting method in 2009 through 2012. In 2013, a $4.5 million decrease was made to the reserve related to the change in accounting method. The decrease is primarily the result of the completion of IRS audits for tax years 2009 to 2012. Further changes to the unrecognized tax position may be recognized as the IRS releases additional guidance as it pertains to the repair allowance for generation assets. The Company recorded an unrecognized tax position of $0.5 million and $1.4 million in 2013 and 2012, respectively, related to depreciation amounts deducted in current and prior year Texas franchise tax returns. The Company recorded an unrecognized tax position of $1.3 million (net of a decrease of $0.4 million) in 2013 related to tax credits taken in prior year Arizona income tax returns. A reconciliation of the December 31, 2013, 2012 and 2011 amount of unrecognized tax benefits is 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 2013 2012 2011 $ $ 9,800 600 — 1,700 (4,900) 7,200 $ $ 9,500 1,600 (900) 1,400 (1,800) 9,800 $ $ 7,300 2,200 — — — 9,500 If recognized, $2.5 million of the unrecognized tax position at December 31, 2013, would affect the effective tax rate. The Company recognized income tax expense for an unrecognized tax position of $1.8 million for the year ended December 31, 2013. The Company recognizes in tax expense interest and penalties related to tax benefits that have not been recognized. During the year ended December 31, 2012, the Company recognized a benefit of $0.3 million in interest. For both of the years ended December 31, 2013 and 2011, the Company recognized interest expense of $0.2 million. The Company had approximately $0.4 million and $0.1 million accrued for the payment of interest and penalties at December 31, 2013 and 2012, respectively. 75 Table of Contents 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 reserves and to meet required renewable portfolio standards, the Company engages in power purchase arrangements which may vary in duration and amount based on evaluation of the Company’s resource needs, the economics of the transactions, and specific renewable portfolio requirements. The Company had entered into the following significant agreements with various counterparties for forward purchases and sales of electricity: Type of Contract Counterparty Quantity Term Power Purchase and Sale Agreement . Power Purchase and Sale Agreement . Power Purchase Agreement................ Power Purchase Agreement................ Power Purchase Agreement................ Power Purchase Agreement................ Power Purchase Agreement................ Freeport Freeport Shell NRG Sun Edison 1 Sun Edison 2 Hatch Solar Energy Center I, LLC 125 MW 100 MW 40 MW Up to December 2008 through December 2014 January 2015 through December 2021 January 2011 through September 2014 20 MW August 2011 through August 2031 August 2011 10 MW 12 MW June 2012 through June 2037 May 2012 through May 2037 June 2012 May 2012 5 MW July 2011 through June 2036 July 2011 Commercial Operation Date N/A N/A N/A Power Purchase Agreement................ Macho Springs Solar, LLC 50 MW 20 years after operational start date Power Purchase Agreement................ Newman Solar, LLC 10 MW 30 years after operational start date Expected May 1, 2014 Expected December 31, 2014 The Company has a firm Power Purchase and Sale Agreement with Freeport-McMoran Copper and Gold Energy Services LLC ("Freeport") which provides for Freeport to deliver energy to the Company from its ownership interest in the Luna Energy Facility (a natural gas-fired combined cycle generation facility located in Luna County, New Mexico) and for the Company to deliver a like amount of energy at Greenlee, Arizona. The Company may purchase the quantities noted in the table above at a specified price at times when energy is not exchanged under the Power Purchase and Sale Agreement. Upon mutual agreement, the contract allows the parties to increase the amount of energy that is purchased and sold under the Power Purchase and Sale Agreement. The parties have agreed to increase the amount to 125 MW through December 2014. The contract was approved by the FERC and continues through December 31, 2021. The Company entered into an agreement in 2009 to purchase capacity and unit contingent energy during 2010 from Shell Energy North America ("Shell"). Under the agreement, the Company provides natural gas to Pyramid Unit No. 4 where Shell has the right to convert natural gas to electric energy. The Company entered into a contract with Shell on May 17, 2010 to extend the term of the capacity and unit contingent energy purchase from January 1, 2011 through September 30, 2014. The Company entered into a 20-year contract with NRG Solar Roadrunner LLC ("NRG") for the purchase of all of the output of a solar photovoltaic plant built in southern New Mexico which began commercial operation in August 2011. The Company has a 25-year purchased power agreement with Hatch Solar Energy Center I, LLC for a solar photovoltaic project located in southern New Mexico which began commercial operation in July 2011. The Company has 25-year purchase power agreements to purchase all of the output of two additional solar photovoltaic projects located in southern New Mexico, SunEdison 1 and SunEdison 2 which achieved commercial operation on June 25, 2012 and May 2, 2012, respectively. The Company entered into these contracts to help meet its renewable portfolio requirements. In May 2013, the NMPRC approved the Company's 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. The term of the purchased power agreement is 20 years from the commercial operation date of the Macho Springs project which is projected to be May 1, 2014. In addition, on September 5, 2013, the Company entered into a purchased power agreement with Newman Solar LLC to purchase, for a term of 30 years, the total output from a solar photovoltaic generation facility of approximately 10 MW that Newman Solar LLC will construct, own and operate on land subleased from the Company in proximity to its Newman Power Station. This solar project is expected to be on line at the end of 2014. 76 Table of Contents Environmental Matters EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS General. The Company is subject to extensive laws, regulations and permit requirements with respect to air and greenhouse gas 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 Company's operations, including sulfur dioxide ("SO2"), particulate matter ("PM"), nitrogen oxides ("NOx") and mercury. Clean Air Interstate Rule/Cross State Air Pollution Rule. The EPA Clean Air Interstate Rule ("CAIR"), as applied to the Company since 2009, 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. While the U.S. Court of Appeals for the District of Columbia Circuit voided CAIR in 2008, on appeal the rule was reinstated until such time as the EPA promulgates a replacement rule. Because the appellate court in August 2012 also vacated the EPA’s proposed replacement, which is called the Cross-State Air Pollution Rule ("CSAPR"), CAIR remains in effect. On March 29, 2013, the U.S. Solicitor General petitioned the U.S. Supreme Court to review the D.C. Circuit's decision to vacate CSAPR. On June 24, 2013, the Supreme Court agreed to hear the case, and oral arguments were heard on December 10, 2013. The timing and outcome of the Supreme Court decision is unknown, and in the meantime, the Company remains subject to CAIR. National Ambient Air Quality Standards. Under the CAA, the EPA sets National Ambient Air Quality Standards ("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 NOx and SO2. In December 2012, the EPA tightened the NAAQS for fine PM, and it is expected to propose more stringent ozone NAAQS in 2014 (with a final rule in 2015). The Company continues to evaluate what impact these final and proposed NAAQS could have on its operations. If the Company is required to install additional equipment to control emissions at its facilities, the revised NAAQS could have a material impact on its operations and financial results. Utility MACT. The operation of coal-fired power plants, such as the Company's Four Corners plant, results in emissions of mercury and other air toxics. In December 2011, the EPA finalized Mercury and Air Toxics Standards (known as the "Utility MACT") for oil-and coal-fired power plants, which requires significant reductions in emissions of mercury and other air toxics. Several judicial and other challenges are being made to this rule. These challenges notwithstanding, companies impacted by the new standards will generally have up to three years to comply. Information from the Four Corners plant operator, APS, indicates that APS currently believes Units 4 and 5 will require no additional modifications to achieve compliance with the Utility MACT standards. Other Laws and Regulations and Risks. As stated above, the Company intends to cease its participation in Four Corners at the expiration of the 50-year participation agreement in 2016. The Company believes that it has better economic and cleaner alternatives for serving the energy needs of its customers than coal-fired generation, which is subject to extensive regulation and litigation. For example, as a result of APS’s recent Best Available Retrofit Technology Federal Implementation Plan compliance strategy notification to the EPA, Four Corners is required to install expensive pollution control equipment in order to continue operation in the future. The Company’s share of the cost of these controls is currently estimated by APS to be approximately $39 million if the Company were to extend its participation in the plant. In addition, the EPA has entered into a consent decree which would require it to sign for publication a final action regarding the regulation of coal combustion residuals ("CCR") under the federal Resource, Conservation and Recovery Act by December 19, 2014. Once issued, the Company may be required to incur significant costs to address CCRs either generated in the past and disposed of at or from Four Corners, as well as CCRs generated in connection with the ongoing operations of Four Corners. Further, assured supplies of water are important for the Company's operations and assets, including Four Corners. Four Corners is located in a region that has been experiencing drought conditions which could affect the plant’s water supply. Four Corners has accordingly been involved in negotiations and proceedings with 77 Table of Contents EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS third parties relating to water supply issues. The drought conditions and related negotiations and proceedings could adversely affect the amount of power available, or the price thereof, from Four Corners. Climate Change. 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 periodically considers 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 applied to the Company, as well as the EPA’s 2010 actions to impose permitting requirements on new and modified sources of GHG emissions, which may create significant costs for power plant owners and operators. On June 25, 2013, President Obama set forth his plan to address climate change. He reiterated a goal of reducing GHG "in the range of 17 percent" below 2005 levels by 2020. The plan included a variety of executive actions, including future regulatory measures to reduce carbon emissions from power plants. In a White House memorandum of the same date, the President directed the EPA to issue a new proposal for GHG rulemaking addressing new power plants by September 20, 2013, and a rule for existing power plants by June 1, 2014. The formal proposal for new power plants was published in the Federal Register on January 8, 2014. The Company continues its review of the new proposal and plans to participate in the 60-day post-publication comment period. Given the very significant remaining uncertainties regarding these rules, the Company believes it is impossible to meaningfully quantify the costs of these potential requirements at present. In addition, almost half the U.S. states, either individually and/or through multi-state regional initiatives, have begun to consider how to address GHG emissions and have developed, or are actively considering the development of emission inventories or regional GHG cap and trade programs. While a significant portion of the Company's generation assets are nuclear or gas-fired, and as a result, the Company believes that its greenhouse gas emissions are low relative to electric power companies who rely more on coal-fired generation, current and future legislation and regulation of GHGs or any future related litigation could impose significant costs and/or operating restrictions on the Company, reduced demand for the power the Company generates and/or require the Company to purchase rights to emit GHGs, any of which could be material to the Company's business, financial condition, reputation or results of operations. Climate change also has potential physical effects that could be relevant to the Company's business. In particular, some studies suggest that climate change could affect the Company's service area by causing higher temperatures, less winter precipitation and less spring runoff, as well as by causing more extreme weather events. Such developments could change the demand for power in the region and could also impact the price or ready availability of water supplies or affect maintenance needs and the reliability of Company equipment. The Company believes that material effects on the Company's business or results of operations may result from the physical consequences of climate change, the regulatory approach to climate change ultimately selected and implemented by governmental authorities, or both. Given the very significant remaining uncertainties regarding whether and how these issues will be regulated, as well as the timing and severity of any physical effects of climate change, the Company believes it is impossible to meaningfully quantify the costs of these potential impacts at present. Environmental Litigation and Investigations. Since 2009, the EPA and certain environmental organizations have been scrutinizing, and in some cases, have filed lawsuits, relating to certain air emissions and air permitting matters related to Four Corners. In particular, 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. In March 2012, the DOJ provided APS with a draft consent decree to settle the EPA matter, which decree contains specific provisions for the reduction and control of NOx, SO2, and PM, as well as provisions for a civil penalty, and expenditures on environmental mitigation projects with an emphasis on projects that address alleged harm to the Navajo Nation. Settlement discussions are on-going and the Company is unable to predict the outcome of these settlement negotiations. The Company has accrued a total of $0.5 million as a loss contingency related to this matter. The Company received notice that Earthjustice filed a lawsuit in the United States District Court for New Mexico on October 4, 2011 for alleged violations of the Prevention of Significant Deterioration ("PSD") provisions of the CAA related to Four Corners. On January 6, 2012, Earthjustice filed a First Amended Complaint adding claims for violations of the CAA's New Source Performance Standards ("NSPS") program. Among other things, the plaintiffs seek to have the court enjoin operations at Four Corners until APS applies for and obtains any required PSD permits and complies with the referenced NSPS program. The plaintiffs further request the court to order the payment of civil penalties, including a beneficial mitigation project. On April 2, 2012, APS and the other Four Corners' participants filed motions to dismiss with the court. The case is being held in abeyance while the parties seek to negotiate a settlement. On March 30, 2013, upon joint motion of the parties, the court issued an order deeming the 78 Table of Contents EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS motions to dismiss withdrawn without prejudice during pendency of the stay. At such time as the stay is lifted, APS, the Company and the other Four Corners participants may reinstate the motions to dismiss. On February 14, 2014, the parties filed a joint motion to extend the stay in the case by 30 days holding the matter in abeyance until March 17, 2014. The Company is unable to predict the outcome of this litigation. New Mexico Tax Matter Related to Coal Supplied to Four Corners On May 23, 2013, the New Mexico Taxation and Revenue Department issued a notice of assessment for coal severance surtax, penalty, and interest totaling approximately $30 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 New Mexico Taxation and Revenue Department 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. APS believes the Assessment and the refund claim denial are without merit. The Company cannot predict the timing, results, or potential impacts of the outcome of this litigation. Lease Agreements The Company leases land in El Paso adjacent to the Newman Power Station under a lease which expires in June 2033 with a renewal option of 25 years. In addition, the Company leases certain warehouse facilities in El Paso under a lease which expires in December 2015. The Company also has several other leases for office, parking facilities and equipment which expire within the next four years . These lease agreements do not impose any restrictions relating to issuance of additional debt, payment of dividends or entering into other lease arrangements. The Company has no significant capital lease agreements. The Company's total annual rental expense related to operating leases was $1.2 million, $1.3 million, and $1.1 million for 2013, 2012 and 2011, respectively. As of December 31, 2013, the Company’s minimum future rental payments for the next five years are as follows (in thousands): 2014................................................. $ 2015................................................. 2016................................................. 2017................................................. 2018................................................. 1,081 1,028 600 442 408 Union Matters The Company has approximately 1,000 employees, about 40% 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, 2013, with Local 960 for a three-year term ending September 2, 2016. The agreement provides for pay increases of 3% on September 3, 2013, 3% on September 3, 2014 and 2.25% on September 3, 2015. L. Litigation The Company is a party to various legal actions. In many of these matters, the Company has excess casualty liability insurance that covers the various claims, actions and complaints. Based upon a review of these claims and applicable insurance coverage, the Company believes that none of these claims will have a material adverse effect on the financial position, results of operations or cash flows of the Company. See Note C and Note K for discussion of the effects of government legislation and regulation on the Company. 79 Table of Contents M. Employee Benefits Retirement Plans EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS The Company’s Retirement Income Plan (the "Retirement Plan") covers employees who have completed one year of service with the Company and work at least a minimum number of hours each year. The Retirement Plan is a qualified noncontributory defined benefit plan. Retirement benefits are based on the employee's final average pay and years of service. Upon retirement or death of a vested plan participant, assets of the Retirement Plan are used to pay benefit obligations under the Retirement Plan. Contributions from the Company are at least the minimum funding amounts required by the IRS under provisions of the Retirement Plan, as actuarially calculated. The assets of the Retirement Plan are 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 other plan, the Excess Benefit Plan was adopted in 2004 and covers certain active and former employees of the Company. The benefit cost for the non-qualified retirement plans are based on substantially the same actuarial methods and economic assumptions as those used for the Retirement Plan. The Company complies with FASB guidance on disclosure for pension and other post-retirement plans that requires disclosure of investment policies and strategies, categories of investment and fair value measurements of plan assets, and significant concentrations of risk. The obligations and funded status of the plans are presented below (in thousands): December 31, 2013 2012 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 on plan assets................................ Employer contribution ........................................ Benefits paid ....................................................... Fair value of plan assets at end of year........ Funded status at end of year ........................ $ $ 320,846 9,137 12,742 (15,373) (9,537) 317,815 220,568 31,800 15,000 (9,537) 257,831 (59,984) $ $ 27,241 190 872 (533) (1,872) 25,898 $ 296,293 8,530 12,594 12,417 (8,988) 320,846 — — 1,872 (1,872) — (25,898) $ 191,369 20,187 18,000 (8,988) 220,568 (100,278) $ 26,547 299 963 1,338 (1,906) 27,241 — — 1,906 (1,906) — (27,241) 80 Table of Contents EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS Amounts recognized in the Company's balance sheets consist of the following (in thousands): December 31, 2013 2012 Retirement Income Plan Non-Qualified Retirement Plans Retirement Income Plan Non-Qualified Retirement Plans Current liabilities ......................................................................... $ Noncurrent liabilities ................................................................... Total...................................................................................... $ — $ (59,984) (59,984) $ (1,870) $ (24,028) (25,898) $ — $ (100,278) (100,278) $ (1,829) (25,412) (27,241) The accumulated benefit obligation in excess of plan assets is as follows (in thousands): December 31, 2013 2012 Projected benefit obligation......................................................... $ Accumulated benefit obligation .................................................. Fair value of plan assets .............................................................. Retirement Income Plan (317,815) $ (275,555) 257,831 Non-Qualified Retirement Plans (25,898) $ (25,077) — Retirement Income Plan (320,846) $ (274,890) 220,568 Non-Qualified Retirement Plans (27,241) (26,363) — Amounts recognized in accumulated other comprehensive income consist of the following (in thousands): Net loss ........................................................................................ $ Prior service cost ......................................................................... Total...................................................................................... $ Years Ended December 31, 2013 2012 Retirement Income Plan Non-Qualified Retirement Plans 85,261 — 85,261 $ $ 8,508 219 8,727 Retirement Income Plan 125,763 3 125,766 $ $ Non-Qualified Retirement Plans $ $ 9,701 314 10,015 The following are the weighted-average actuarial assumptions used to determine the benefit obligations: December 31, 2013 Non-Qualified 2012 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 . 4.9% 4.75% 3.9% N/A 4.9% 4.75% 4.0% 4.75% 3.1% N/A 4.0% 4.75% The Company reassesses various actuarial assumptions at least on an annual basis. The discount rate is reviewed at each measurement date. The discount rate used to measure obligations is based on a spot rate yield curve that matches projected future payments with the appropriate interest rate applicable to the timing of the projected future benefit payments. A 1% increase in the discount rate would decrease the December 31, 2013 retirement plans' projected benefit obligation by 12.5%. A 1% decrease in the discount rate would increase the December 31, 2013 retirement plans' projected benefit obligation by 15.5%. 81 Table of Contents EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS The components of net periodic benefit cost are presented below (in thousands): Years Ended December 31, 2013 2012 2011 Retirement Income Plan Non-Qualified Retirement Plans Retirement Income Plan Non-Qualified Retirement Plans Retirement Income Plan Non-Qualified Retirement Plans $ 9,137 12,742 (17,108) 10,437 3 190 872 — 661 94 $ $ 8,530 12,594 (14,443) 10,729 21 299 963 — 627 94 $ $ 6,590 12,871 (14,095) 6,190 21 260 1,116 — 354 94 15,211 $ 1,817 $ 17,431 $ 1,983 $ 11,577 $ 1,824 Service cost .............................. $ Interest cost .............................. Expected return on plan assets. Amortization of: Net loss ............................. Prior service cost............... Net periodic benefit cost............................. $ The changes in benefit obligations recognized in other comprehensive income are presented below (in thousands): 2013 2012 2011 Years Ended December 31, Net (gain) loss .......................... $ Amortization of: Net loss.............................. Prior service cost ............... Total recognized in other comprehensive income...... $ Retirement Income Plan (30,065) $ Non-Qualified Retirement Plans Retirement Income Plan Non-Qualified Retirement Plans Retirement Income Plan Non-Qualified Retirement Plans (533) $ 6,672 $ 1,337 $ 40,181 $ 2,980 (10,437) (3) (661) (94) (10,729) (21) (627) (94) (6,190) (21) (354) (94) (40,505) $ (1,288) $ (4,078) $ 616 $ 33,970 $ 2,532 The total amount recognized in net periodic benefit costs and other comprehensive income are presented below (in thousands): Years Ended December 31, 2013 2012 2011 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 ............. $ (25,294) $ 529 $ 13,353 $ 2,599 $ 45,547 $ 4,356 The following are amounts in accumulated other comprehensive income that are expected to be recognized as components of net periodic benefit cost during 2014 (in thousands): Net loss ........................................................................................................................................... $ Prior service cost............................................................................................................................. $ 6,270 — 570 90 Retirement Income Plan Non-Qualified Retirement Plans 82 Table of Contents EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS The following are the weighted-average actuarial assumptions used to determine the net periodic benefit cost for the twelve months ended December 31: 2013 Non-Qualified 2012 Non-Qualified 2011 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 4.0% 3.1% 4.0% 4.3% 3.6% 4.1% 5.4% 4.6% 5.3% 7.5% N/A N/A 7.5% N/A N/A 7.5% N/A N/A 4.75% N/A 4.75% 5.0% N/A 5.0% 5.0% N/A 5.0% Discount rate...... Expected long- term return on plan assets.......... Rate of compensation increase .............. The Company reassesses various actuarial assumptions at least on an annual basis. The discount rate is reviewed at each measurement date. The discount rate used to measure net periodic benefit cost is based on a spot rate yield curve that matches projected future payments with the appropriate interest rate applicable to the timing of the projected future benefit payments. The Company’s overall expected long-term rate of return on assets is 7.5% effective January 1, 2013, 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, 2013 55% 40% 5% 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. The Retirement Plan fund also invests in a real estate limited partnership. 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 returns are based on estimates of long-term inflation rate, real rate of return, 10-year Treasury bond premium over cash and equity risk premium. Fixed income returns are based on maturity, long- term inflation, real rate of return and credit spreads. FASB guidance on disclosure for pension plans requires disclosure of fair value measurements of plan assets. To increase consistency and comparability in fair value measurements FASB guidance on fair value measurements established a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value into three levels as follows: • Level 1 – Observable inputs that reflect quoted market prices for identical assets and liabilities in active markets. Prices or 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. • Level 2 – Inputs other than quoted market prices included in Level 1 that are observable for the asset or liability either directly or indirectly. The fair value of the Guaranteed Investment Contract is based on market interest rates of investments with similar terms and risk characteristics. The Common Collective Trusts are valued using the net asset value ("NAV") provided by the administrator of the fund. The NAV price is quoted on a restrictive market although the underlying investments are traded on active markets. • Level 3 – Unobservable inputs using data that is not corroborated by market data. The fair value of the real estate limited partnership is reported at the NAV of the investment. 83 Table of Contents EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS During 2013, the Company sold the majority of its assets held in active markets, classified as Level 1, and invested these assets in common collective trusts which are classified as Level 2. The fair value of the Company’s Retirement Plan assets at December 31, 2013 and 2012, and the level within the three levels of the fair value hierarchy defined by FASB guidance on fair value measurements are presented in the table below (in thousands): Description of Securities Cash and Cash Equivalents ......................................................... $ Guaranteed Investment Contract ................................................. Common Collective Trusts (a) Equity funds ............................................................................. Fixed income funds.................................................................. Total Common Collective Trusts.......................................... Limited Partnership Interest in Real Estate (b) ........................... Total Plan Investments ......................................................... $ Fair Value as of December 31, 2013 Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) $ 940 1,126 142,960 103,948 246,908 8,857 257,831 $ 940 — — — — — 940 $ — $ 1,126 142,960 103,948 246,908 — 248,034 $ — — — — — 8,857 8,857 Description of Securities Cash and Cash Equivalents ......................................................... $ U.S. Treasury Securities .............................................................. Guaranteed Investment Contract ................................................. Common Stock ............................................................................ Mutual Funds - Fixed Income ..................................................... Mutual Funds - Equity................................................................. Limited Partnership Interest in Real Estate (b) ........................... Total Plan Investments ......................................................... $ Fair Value as of December 31, 2012 Quoted Prices in Active Markets for Identical Assets (Level 1) 9,163 24,854 1,059 52,149 59,150 65,634 8,559 220,568 $ $ 9,163 24,854 — 52,149 59,150 65,634 — 210,950 Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) — $ — 1,059 — — — — 1,059 $ — — — — — — 8,559 8,559 _____________________ (a) The Common Collective Trusts are invested in equity or fixed income securities, or a combination thereof. The investment objective of each trust 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 is restricted from selling its partnership interest during the life of the partnership which is generally 5-7 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 table below reflects the changes in the fair value of investments in real estate during the period (in thousands): Balances at December 31, 2011 .................................................................................. $ Unrealized gain in fair value ................................................................................ Balances at December 31, 2012 .................................................................................. Unrealized gain in fair value ................................................................................ Balances at December 31, 2013 .................................................................................. $ 8,511 48 8,559 298 8,857 Fair Value of Investments in Real Estate 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, 2013 and 2012. There were no purchases, sales, issuances, and 84 $ $ $ Table of Contents EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS settlements related to the assets in the Level 3 fair value measurement category during the twelve month periods ending December 31, 2013 and 2012. 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 $13.9 million to its retirement plans in 2014. The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid (in thousands): Retirement Income Plan Non-Qualified Retirement Plans 2014 ........................................................................... $ 2015 ........................................................................... 2016 ........................................................................... 2017 ........................................................................... 2018 ........................................................................... 2019-2023.................................................................. $ 10,902 12,015 13,180 14,440 15,807 96,510 1,870 1,818 1,772 1,829 1,715 9,447 In 2014, the Company will implement a redesigned Retirement Income Plan and Excess Benefit Plan. Effective April 1, 2014, the Company will offer 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 will also include an enhanced employer matching contribution to the employee’s respective 401(k) Defined Contribution Plan (discussed below). For employees that elect the new cash balance pension plan, the pension benefit earned under the existing final average pay pension plan will be frozen as of March 31, 2014. Employees hired after January 1, 2014 will be automatically enrolled in the cash balance pension plan. The Company anticipates remeasuring the assets and liabilities of the retirement plans during the first quarter of 2014. 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 2013, 2012 and 2011 were $1.9 million, $1.8 million, and $1.7 million, respectively. Historically, the Company has provided a 50 percent matching contribution up to 6 percent of the employee’s compensation subject to certain other limits and exclusions. Effective April 1, 2014, for employees who enroll in the cash balance pension plan (discussed above), the Company will provide a 100 percent matching contribution up to 6 percent of the employee's compensation subject to certain other limits and exclusions. Other Postretirement Benefits The Company provides certain health care benefits for retired employees and their eligible dependents and life insurance benefits for retired employees only. Substantially all of the Company’s employees may become eligible for those benefits if they retire while working for the Company. Contributions from the Company are no more than the IRS tax deductible limit, as actuarially calculated. The assets of the plan are 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 determined that the prescription drug benefits of its plan were actuarially equivalent to the Medicare Part D benefit provided for in the Medicare Prescription Drug, Improvement, and Modernization Act of 2003. FASB guidance on accounting and disclosure requirements related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003 requires measurement of the postretirement benefit obligation, the plan assets, and the net periodic postretirement benefit cost to 85 Table of Contents EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS reflect the effects of the subsidy. In March 2010, the President signed into law comprehensive health care reform legislation under the Patient Protection and Affordable Care Act and the Health Care Education and Affordability Reconciliation Act (the "Acts"). The Company modified the operations of the plan to conform to the effective provisions of the Acts. 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 gain .......................................................................................................................... Amendment (a)........................................................................................................................ Benefits paid............................................................................................................................ Retiree contributions ............................................................................................................... Medicare Part D subsidy ......................................................................................................... Benefit obligation at end of year ...................................................................................... Change in plan assets: Fair value of plan assets at end of prior year........................................................................... Actual return on plan assets..................................................................................................... Employer contribution............................................................................................................. Benefits paid............................................................................................................................ Retiree contributions ............................................................................................................... Medicare Part D subsidy ......................................................................................................... Fair value of plan assets at end of year ............................................................................ Funded status (b) .............................................................................................................. $ December 31, 2013 2012 $ 135,680 3,843 5,156 (48,778) (97) (4,013) 1,056 — 92,847 36,510 5,539 3,100 (4,013) 1,056 — 42,192 (50,655) $ 133,272 4,378 5,651 (5,009) — (3,929) 1,086 231 135,680 32,817 2,605 3,700 (3,929) 1,086 231 36,510 (99,170) _____________________ (a) Amendment relates to modification of the Company's Other Postretirement Benefit Plan which limits the Company's premium contribution. The amendment became effective October 3, 2013 and resulted in a remeasurement of the plan. (b) These amounts are recognized in the Company’s balance sheets as a non-current liability. Amounts recognized in accumulated other comprehensive income that have not been recognized as a component of net periodic cost consist of the following (in thousands): Net (gain) loss.................................................... $ Prior service credit............................................. $ December 31, 2013 (38,110) $ (19,210) (57,320) $ 2012 13,630 (24,770) (11,140) The following are the weighted-average actuarial assumptions used to determine the accrued postretirement benefit obligations: Discount rate at end of year ............................................................... Health care cost trend rates: December 31, 2013 2012 4.90% 4.10% Initial........................................................................................... Ultimate ...................................................................................... Year ultimate reached ................................................................. 7.50% 4.50% 2026 7.75% 4.50% 2026 86 Table of Contents EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS The discount rate is reviewed at each measurement date. The discount rate used to measure obligations is based on a spot rate yield curve that matches projected future payments with the appropriate interest rate applicable to the timing of the projected future benefit payments. A 1% increase in the discount rate would decrease the December 31, 2013 accumulated postretirement benefit obligation by 12.8%. A 1% decrease in the discount rate would increase the December 31, 2013 accumulated postretirement benefit obligation by 16.1%. Net periodic benefit cost is made up of the components listed below (in thousands): Years Ended December 31, 2013 2012 2011 Service cost ........................................................................................................... $ Interest cost ........................................................................................................... Expected return on plan assets .............................................................................. Amortization of: Prior service benefit ....................................................................................... Net (gain) loss ................................................................................................ Net periodic benefit cost......................................................................... $ 3,843 5,156 (1,951) (5,657) (626) 765 $ $ 4,378 5,651 (1,714) (5,877) 615 3,053 $ $ 2,988 5,379 (1,823) (5,927) (39) 578 The changes in benefit obligations recognized in other comprehensive income are presented below (in thousands): Net (gain) loss ....................................................................................................... $ Prior service benefit .............................................................................................. Amortization of: 2013 (52,366) $ (97) Prior service benefit ....................................................................................... Net gain (loss) ................................................................................................ Total recognized in other comprehensive income................................................. $ 5,657 626 (46,180) $ 2012 2011 (5,900) $ — 5,877 (615) (638) $ 34,517 — 5,927 39 40,483 Years Ended December 31, The total 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, 2013 (45,415) $ 2012 2011 2,415 $ 41,061 The amount in accumulated other comprehensive income that is expected to be recognized as a component of net periodic benefit cost during 2014 is a prior service benefit of $4.8 million and a net gain of $2.6 million. The following are the weighted-average actuarial assumptions used to determine the net periodic benefit cost for the twelve months ended December 31: 2013 (a) 2012 2011 Discount rate at beginning of year .................................................................. Expected long-term return on plan assets ....................................................... Health care cost trend rates: Initial ........................................................................................................ Ultimate.................................................................................................... Year ultimate reached............................................................................... 4.1% 5.2% 7.75% 4.5% 2026 4.3% 5.2% 8.0% 4.5% 2026 5.5% 5.2% 8.5% 5.0% 2018 _____________________ (a) The Other Postretirement Benefits Plan was remeasured at October 3, 2013 due to a plan amendment. The discount rate increased from 4.1% as of January 1, 2013 to 4.9% at the remeasurement date. All other assumptions remained consistent with assumptions used at January 1, 2013. 87 Table of Contents EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS The Company reassesses various actuarial assumptions at least on an annual basis. The discount rate is reviewed at each measurement date. The discount rate used to measure net periodic benefit cost is based on a spot yield curve that matches projected future payments with the appropriate interest rate applicable to the timing of the projected future benefit payments. For measurement purposes, an 7.75% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2013. 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, 2013 benefit obligation by $14.3 million or $10.8 million, respectively. In addition, a 1% change in said rate would increase or decrease the aggregate 2013 service and interest cost components of the net periodic benefit cost by $2.1 million or $1.2 million, respectively. The Company’s overall expected long-term rate of return on assets, on an after-tax basis, is 5.2% effective January 1, 2013. 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, 2013 65% 30% 5% 100% The Other Postretirement Benefit 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. The asset portfolio also includes cash equivalents and a real estate limited partnership.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 returns are based on estimates of long-term inflation rate, real rate of return, 10-year Treasury bond premium over cash and equity risk premium. Fixed income returns are based on maturity, long-term inflation, real rate of return and credit spreads. FASB guidance on disclosure for other postretirement benefit plans requires disclosure of fair value measurements of plan assets. To increase consistency and comparability in fair value measurements, FASB guidance on fair value measurements established a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value into three levels as follows: • Level 1 – Observable inputs that reflect quoted market prices for identical assets and liabilities in active markets. Prices or securities held in the mutual funds and underlying portfolios of the Other Postretirement Benefits Plan are primarily obtained from independent pricing services. These prices are based on observable market data. • Level 2 – Inputs other than quoted market prices included in Level 1 that are observable for the asset or liability either directly or indirectly. The fair value of municipal securities-tax-exempt are reported at fair value based on evaluated prices that reflect observable market information, such as actual trade information of similar securities, adjusted for observable differences. 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. • Level 3 – Unobservable inputs using data that is not corroborated by market data. The fair value of the real estate limited partnership is reported at the NAV of the investment. During 2013, the Company sold the majority of its assets held in active markets, classified as Level 1, and invested these assets in common collective trusts which are classified as Level 2. The fair value of the Company’s Other Postretirement Benefits Plan assets at December 31, 2013 and 2012, and the level within the three levels of the fair value hierarchy defined by FASB guidance on fair value measurements are presented in the table below (in thousands): 88 Table of Contents EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS Description of Securities Cash and Cash Equivalents ......................................................... $ Common Collective Trusts (a) Fair Value as of December 31, 2013 Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) 33 $ 33 $ — $ — Equity funds ............................................................................. Fixed income funds.................................................................. Total Common Collective Trusts.......................................... Limited Partnership Interest in Real Estate (b) ........................... Total Plan Investments ......................................................... $ 28,077 12,421 40,498 1,661 42,192 $ — — — — 33 Description of Securities Cash and Cash Equivalents ......................................................... $ Municipal Securities – Tax Exempt............................................. Common Stock ............................................................................ Mutual Funds – Equity ................................................................ Limited Partnership Interest in Real Estate (b) ........................... Total Plan Investments ......................................................... $ Fair Value as of December 31, 2012 Quoted Prices in Active Markets for Identical Assets (Level 1) 2,075 12,811 14,397 5,622 1,605 36,510 $ $ 2,075 — 14,397 5,622 — 22,094 28,077 12,421 40,498 — 40,498 $ — — — 1,661 1,661 Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) — $ 12,811 — — — 12,811 $ — — — — 1,605 1,605 $ $ $ ___________________ (a) The Common Collective Trusts are invested in equity or fixed income securities, or a combination thereof. The investment objective of each trust 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 is restricted from selling its partnership interest during the life of the partnership which is generally 5-7 years. Return of investment is realized as land is sold. The fair value of the limited partnership interest in real estate is based on the NAV of the partnership which reflects the appraised value of the land. The table below reflects the changes in the fair value of the investments in real estate during the period (in thousands): Fair Value of Investments in Real Estate Balance at December 31, 2011......... $ Unrealized gain in fair value...... Balance at December 31, 2012......... Unrealized gain in fair value...... Balance at December 31, 2013......... $ 1,596 9 1,605 56 1,661 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, 2013 and 2012. 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, 2013 and 2012. 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 89 Table of Contents EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS 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 does not expect to contribute to its other postretirement benefits plan in 2014. The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid (in thousands): 2014 .................................................................................. $ 2015 .................................................................................. 2016 .................................................................................. 2017 .................................................................................. 2018 .................................................................................. 2019-2023 ......................................................................... 3,024 3,414 3,810 4,230 4,639 28,238 Annual Short-Term Incentive Plan The Annual Short-Term Incentive Plan (the "Incentive Plan") provides for the payment of cash awards to eligible Company employees, including each of its named executive officers. Payment of awards is based on the achievement of performance measures reviewed and approved by the Company’s Board of Directors’ Compensation Committee. Generally, these performance measures are based on meeting certain financial, operational and individual performance criteria. The financial performance goals are based on earnings per share and the operational performance goals are based on safety, regulatory compliance, and customer satisfaction. If a specified level of earnings per share is not attained, no amounts will be paid under the Incentive Plan. In 2013, the Company reached the required levels of earnings per share, safety, regulatory compliance, and customer satisfaction goals for an incentive payment of $4.0 million. The Company reached the required levels of earnings per share, safety, and regulatory compliance goals for an incentive payment of $7.9 million and $7.3 million in 2012 and 2011, respectively. The Company has renewed the Incentive Plan in 2014 with similar goals. N. Franchises and Significant Customers El Paso and Las Cruces Franchises The Company has a franchise agreement with El Paso, the largest city it serves. The franchise agreement allows the Company to utilize public rights-of-way necessary to serve its retail customers within El Paso. The Company is also providing electric distribution service to Las Cruces under an implied franchise by satisfying all obligations under the franchise agreement that expired on April 30, 2009. The franchise arrangements held between the Company and the cities of El Paso and Las Cruces are detailed below: City El Paso Las Cruces Period August 1, 2010 - Present February 1, 2000 - Present Franchise Fee (a) (b) 4.00% 2.00% _________________ (a) Based on a percentage of revenue. (b) 0.75% of the El Paso franchise fee is to be placed in a restricted fund to be used solely for economic development and renewable energy purposes. Military Installations The Company serves Holloman Air Force Base ("Holloman"), White Sands Missile Range ("White Sands") and Fort Bliss. The military installations represent approximately 5% of the Company's annual retail revenues. Fort Bliss takes retail electric service from the Company under the applicable Texas tariffs. The Company is serving White Sands under the applicable New Mexico tariffs. In March 2006, the Company signed a contract with Holloman that provides for the Company to provide retail electric service and limited wheeling services to Holloman for a ten-year term which expires in January 2016. 90 Table of Contents EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS O. Financial Instruments and Investments FASB guidance requires the Company to disclose estimated fair values for its financial instruments. The Company has determined that cash and temporary investments, investment in debt securities, accounts receivable, decommissioning trust funds, long-term debt, short-term borrowings under the RCF, accounts payable and customer deposits meet the definition of financial instruments. The carrying amounts of cash and temporary investments, accounts receivable, accounts payable and customer deposits approximate fair value because of the short maturity of these items. Investments in debt securities and decommissioning trust funds are carried at fair value. Long-Term Debt and Short-Term Borrowings Under the RCF. The fair values of the Company's long-term debt and short- term borrowings under the RCF are based on estimated market prices for similar issues and are presented below (in thousands): December 31, 2013 2012 Carrying Amount Estimated Fair Value Carrying Amount Estimated Fair Value Pollution Control Bonds .............................................................. $ Senior Notes ................................................................................ RGRT Senior Notes (1) ............................................................... RCF (1)........................................................................................ 193,135 696,485 110,000 14,352 Total............................................................................... $ 1,013,972 $ 193,990 734,515 115,850 14,352 $ 1,058,707 $ 193,135 696,400 110,000 22,155 $ 1,021,690 $ 215,228 823,497 120,985 22,155 $ 1,181,865 __________________ (1) Nuclear fuel financing as of December 31, 2013 and December 31, 2012 is funded through the $110 million RGRT Senior Notes and $14.4 million and $22.2 million, respectively under the RCF. As of December 31, 2013 and 2012, no 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 2014, approximately $0.4 million of this accumulated other comprehensive loss item will be reclassified to interest expense. Contracts and Derivative Accounting. The Company uses commodity contracts to manage its exposure to price and availability risks for fuel purchases and power sales and purchases and these contracts generally have the characteristics of derivatives. The Company does not trade or use these instruments with the objective of earning financial gains on the commodity price fluctuations. The Company has determined that all such contracts outstanding at December 31, 2013, except for certain natural gas commodity contracts with optionality features, that had the characteristics of derivatives met the "normal purchases and normal sales" exception provided in FASB guidance for accounting for derivative instruments and hedging activities, and, as such, were not required to be accounted for as derivatives. The Company determined that certain of its natural gas commodity contracts with optionality features are not eligible for the normal purchases exception and, therefore, are required to be accounted for as derivative instruments pursuant to FASB guidance for accounting for derivative instruments and hedging activities. However, as of December 31, 2013, the variable, market- based pricing provisions of existing gas contracts are such that these derivative instruments have no significant fair value. Marketable Securities. The Company’s marketable securities, included in decommissioning trust funds in the balance sheets, are reported at fair value which was $214.1 million and $187.1 million at December 31, 2013 and 2012, respectively. These securities are classified as available for sale under FASB guidance for certain investments in debt and equity securities and are valued using prices and other relevant information generated by market transactions involving identical or comparable securities. The reported fair values include gross unrealized losses on marketable securities whose impairment the Company has deemed to be temporary. The tables below present the gross unrealized losses and the fair value of these securities, aggregated by investment category and length of time that individual securities have been in a continuous unrealized loss position (in thousands): 91 Table of Contents EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS December 31, 2013 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...................................................... 6,444 8,114 12,286 3,284 30,128 2,305 Total Temporarily Impaired Securities...... $ 32,433 $ $ ____________________ (1) Includes approximately 122 securities. (169) $ 1,421 (245) 10,866 (335) 7,782 (96) 901 (845) 20,970 (126) — (971) $ 20,970 $ $ (119) $ (840) (479) (54) (1,492) — 7,865 18,980 20,068 4,185 51,098 2,305 (1,492) $ 53,403 $ $ (288) (1,085) (814) (150) (2,337) (126) (2,463) December 31, 2012 Less than 12 Months 12 Months or Longer Total Fair Value Unrealized Losses Fair Value Unrealized Losses Fair Value Unrealized Losses Description of Securities (2): Federal Agency Mortgage Backed Securities ....... $ U.S. Government Bonds ....................................... Municipal Obligations........................................... Corporate Obligations ........................................... Total Debt Securities...................................... Common stock ...................................................... 1,792 6,633 5,306 452 14,183 3,603 Total Temporarily Impaired Securities...... $ 17,786 $ $ (5) $ 416 (79) 4,457 (39) 5,760 (11) — (134) 10,633 (409) — (543) $ 10,633 $ $ ______________________ (2) Includes approximately 65 securities. (9) $ (114) (241) — (364) — 2,208 11,090 11,066 452 24,816 3,603 (364) $ 28,419 $ $ (14) (193) (280) (11) (498) (409) (907) The Company monitors the length of time the security trades below its cost basis along with the amount and percentage of the unrealized loss in determining if a decline in fair value of marketable securities below recorded cost is considered to be other than temporary. In addition, the Company will research the future prospects of individual securities as necessary. As a result of these factors, as well as the Company’s intent and ability to hold these securities until their market price recovers, these securities are considered temporarily impaired. The Company does not anticipate expending monies held in trust before 2044 or a later period when the Company begins to decommission Palo Verde. The reported fair values also include gross unrealized gains on marketable securities which have not been recognized in the Company’s net income. The table below presents the unrecognized gross unrealized gains and the fair value of these securities, aggregated by investment category (in thousands): 92 Table of Contents EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS 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, 2013 December 31, 2012 Fair Value Unrealized Gains Fair Value Unrealized Gains 9,929 6,258 8,783 9,188 34,158 103,808 16,802 5,924 160,692 $ $ 433 126 450 506 1,515 43,145 3,081 — 47,741 $ $ 17,289 13,295 22,797 12,378 65,759 73,210 15,194 4,471 158,634 $ $ 1,036 678 1,531 1,134 4,379 22,839 1,821 — 29,039 The Company’s marketable securities include investments in municipal, corporate and federal debt obligations. Substantially all of the Company’s mortgage-backed securities, based on contractual maturity, are due in ten years or more. The mortgage- backed securities have an estimated weighted average maturity which generally range from three years to eight years and reflects anticipated future prepayments. The contractual year for maturity for these available-for-sale securities as of December 31, 2013 is as follows (in thousands): Municipal Debt Obligations............................... $ Corporate Debt Obligations ............................... U.S. Government Bonds .................................... $ 28,851 13,373 25,238 $ 1,486 321 1,216 $ 13,311 3,711 14,149 $ 10,920 5,525 7,217 3,134 3,816 2,656 Total 2014 2015 through 2018 2019 through 2023 2024 and Beyond The Company recognizes impairment losses on certain of its securities deemed to be other than temporary. In accordance with FASB guidance, these impairment losses are recognized in net income, and a lower cost basis is established for these securities. For the twelve months ended December 31, 2013, 2012, and 2011 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 ......................................... $ — $ (479) $ (2,116) 2013 2012 2011 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, 2013, 2012, and 2011 and the related effects on pre-tax income are as follows (in thousands): Proceeds from sales or maturities 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 (losses) in pre-tax income ............................................................. $ Net unrealized holding gains included in accumulated other comprehensive income ................................................................................................................... $ Net (gains) losses reclassified out of accumulated other comprehensive income Net gains in other comprehensive income ............................................................ $ 2013 2012 2011 56,148 986 (433) — 553 17,699 (553) 17,146 $ $ $ $ $ 98,542 $ 82,926 $ 1,478 (2,041) (479) (1,042) $ 9,927 1,042 10,969 $ $ 1,479 (721) (2,116) (1,358) 1,570 1,358 2,928 93 Table of Contents EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS Fair Value Measurements. FASB guidance requires the Company to provide expanded quantitative disclosures for financial assets and liabilities recorded on the balance sheet at fair value. Financial assets carried at fair value include the Company's decommissioning trust investments and investments in debt securities which are included in deferred charges and other assets on the balance sheets. The Company has no liabilities that are measured at fair value on a recurring basis. The FASB guidance establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value into three levels as follows: • Level 1 - Observable inputs that reflect quoted market prices for identical assets and liabilities in active markets. Financial assets utilizing Level 1 inputs include the nuclear decommissioning trust investments in active exchange-traded equity securities, mutual funds and U.S. Treasury securities that are in a highly liquid and active market. • Level 2 - Inputs other than quoted market prices included in Level 1 that are observable for the asset or liability either directly or indirectly. Financial assets utilizing Level 2 inputs include the nuclear decommissioning trust investments in fixed income securities. The fair value of these financial instruments is based on evaluated prices that reflect observable market information, such as actual trade information of similar securities, adjusted for observable differences. • Level 3 - Unobservable inputs using data that is not corroborated by market data and primarily based on internal Company analysis using models and various other analyses. Financial assets utilizing Level 3 inputs include the Company's investments in debt securities. The securities in the Company’s decommissioning trust funds are valued using prices and other relevant information generated by market transactions involving identical or comparable securities. FASB guidance identifies this valuation technique as the "market approach" with observable inputs. The Company analyzes available-for-sale securities to determine if losses are other than temporary. The fair value of the Company’s decommissioning trust funds and investments in debt securities, at December 31, 2013 and 2012, and the level within the three levels of the fair value hierarchy defined by FASB guidance are presented in the table below (in thousands): Description of Securities Trading Securities: Fair Value as of December 31, 2013 Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) 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 ............................................... Cash and Cash Equivalents ..................................... Total available for sale ..................................... $ $ $ 1,555 25,238 17,794 28,851 13,373 85,256 106,113 16,802 5,924 214,095 $ $ $ — $ — $ 1,555 25,238 — — — 25,238 106,113 16,802 5,924 154,077 $ — $ 17,794 28,851 13,373 60,018 — — — 60,018 $ $ — — — — — — — — — 94 Table of Contents EL PASO ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS Description of Securities Trading Securities: Fair Value as of December 31, 2012 Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Investments in Debt Securities ............................................. $ 1,295 Available for sale: U.S. Government Bonds....................................................... $ Federal Agency Mortgage Backed Securities ...................... Municipal Obligations.......................................................... Corporate Obligations .......................................................... Subtotal, Debt Securities............................................... Common Stock..................................................................... Equity Mutual Funds............................................................ Cash and Cash Equivalents .................................................. Total available for sale .................................................. $ 24,385 19,497 33,863 12,830 90,575 76,813 15,194 4,471 187,053 $ $ $ — $ — $ 1,295 24,385 — — — 24,385 76,813 15,194 4,471 120,863 $ — $ 19,497 33,863 12,830 66,190 — — — 66,190 $ $ — — — — — — — — — 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 ....................................................................................................................... $ 1,295 $ 1,120 2013 2012 Net unrealized gains in fair value recognized in income (a) ................................................... Balance at December 31 ................................................................................................................. $ _____________________ (a) These amounts are reflected in the Company's statement of operations as investment and interest income. 260 1,555 $ 175 1,295 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, 2013 and 2012. 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, 2013 and 2012. P. Supplemental Statements of Cash Flows Disclosures Years Ended December 31, 2013 2012 2011 (In thousands) Cash paid (received) for: Interest on long-term debt and borrowing under the revolving credit facility ............................................................................................................. $ Income taxes paid (refund), net ...................................................................... 53,752 $ 50,189 $ 244 5,031 48,797 (6,260) Non-cash financing activities: Grants of restricted shares of common stock.................................................. Issuance of performance shares ...................................................................... Acquisition of treasury stock for options exercised ....................................... 3,224 849 — 2,411 1,193 — 3,268 628 500 95 Table of Contents 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. 2013 Quarters 2012 Quarters 4th 3rd 2nd 1st 4th 3rd 2nd 1st (In thousands except for share data) Operating revenues (1) .............. $190,297 Operating income ...................... 6,050 $282,661 85,896 $240,114 54,344 $177,290 19,345 $188,802 13,708 $267,249 86,396 $228,252 56,512 $168,578 12,042 Net income................................. 1,191 50,565 29,193 7,634 4,819 51,789 30,894 3,344 Basic earnings per share: Net income ......................... 0.03 1.26 0.73 0.19 0.12 1.29 0.77 0.08 Diluted earnings per share: Net income ......................... Dividends declared per share of common stock............................ 0.03 1.26 0.72 0.265 0.265 0.265 0.19 0.25 0.12 0.25 1.29 0.25 0.77 0.25 0.08 0.22 ________________ (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. 96 Table of Contents 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 Securities Exchange Act of 1934 of our disclosure controls and procedures as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934. Based on that evaluation, our chief executive officer and our chief financial officer concluded that, as of December 31, 2013, 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 43 of this report. Changes in internal control over financial reporting. There were no changes in our internal control over financial reporting in connection with the evaluation required by paragraph (d) of the Securities Exchange Act of 1934 Rules 13a-15 or 15d-15, that occurred during the quarter ended December 31, 2013, 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 97 

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