Edgar Filing: EL PASO ELECTRIC CO /TX/

Since 1999
(a)

Authorized
Shares

Shares repurchased (b)

Cost, including commission (in thousands)

Total remaining shares available for repurchase at December 31, 2015

10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

_______________________

Form 10-K

(Mark One)



x	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2015



o	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		74-0607870
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

Stanton Tower, 100 North Stanton, El Paso, Texas		79901
(Address of principal executive offices)		(Zip Code)

Registrant’s telephone number, including area code: (915) 543-5711

Securities Registered Pursuant to Section 12(b) of the Act:



Title of each class		Name of each exchange on which registered
Common Stock, No Par Value		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 x 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 x

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 x 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 x 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. x

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	x	Accelerated filer	o

Non-accelerated filer	o (Do not check if a smaller reporting company)	Smaller reporting company	o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). YES ¨ NO x

As of June 30, 2015, the aggregate market value of the voting stock held by non-affiliates of the registrant was $1,380,612,681 (based on the closing price as quoted on the New York Stock Exchange on that date).

As of January 31, 2016, there were 40,483,000 shares of the Company’s no par value common stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant’s definitive Proxy Statement for the 2016 annual meeting of its shareholders are incorporated by reference into Part III of this report.

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DEFINITIONS

The following abbreviations, acronyms or defined terms used in this report are defined below:



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
HAFB		Holloman Air Force Base
IRS		Internal Revenue Service
kV		Kilovolt(s)
kW		Kilowatt(s)
kWh		Kilowatt-hour(s)
Las Cruces		City of Las Cruces, New Mexico
MW		Megawatt(s)
MWh		Megawatt-hour(s)
NMPRC		New Mexico Public Regulation Commission
Net dependable generating capability		The maximum load net of plant operating requirements that a generating plant can supply under specified conditions for a given time interval, without exceeding approved limits of temperature and stress
NRC		Nuclear Regulatory Commission
Palo Verde		Palo Verde Nuclear Generating Station
Palo Verde Participants		Those utilities that share in power and energy entitlements, and bear certain allocated costs, with respect to Palo Verde pursuant to the ANPP Participation Agreement
PNM		Public Service Company of New Mexico
PUCT		Public Utility Commission of Texas
RGEC		Rio Grande Electric Cooperative
RGRT		Rio Grande Resources Trust
TEP		Tucson Electric Power Company
White Sands		White Sands Missile Range



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TABLE OF CONTENTS




Item	Description	Page
	PART I
1	Business	1
1A	Risk Factors	15
1B	Unresolved Staff Comments	20
2	Properties	20
3	Legal Proceedings	20
4	Mine Safety Disclosures	20


	PART II
5	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	21
6	Selected Financial Data	24
7	Management’s Discussion and Analysis of Financial Condition and Results of Operations	25
7A	Quantitative and Qualitative Disclosures About Market Risk	44
8	Financial Statements and Supplementary Data	46
9	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	105
9A	Controls and Procedures	105
9B	Other Information	105

	PART III
10	Directors, Executive Officers and Corporate Governance	106
11	Executive Compensation	107
12	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	107
13	Certain Relationships and Related Transactions, and Director Independence	107
14	Principal Accounting Fees and Services	107

	PART IV
15	Exhibits and Financial Statement Schedules	108



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FORWARD-LOOKING STATEMENTS

Certain matters discussed in this Annual Report on Form 10-K other than statements of historical fact are "forward-looking statements," within the meaning of Section 27A of the Securities Act of 1933, as amended (the "Securities Act"), and Section 21E of the Securities Exchange Act of 1934, as amended (the "Exchange Act"). Forward-looking statements often include words like we "believe", "anticipate", "target", "project", "expect", "predict", "pro forma", "estimate", "intend", "will", "is designed to", "plan" and words of similar meaning, or by the Company's discussion of strategies or trends. Forward-looking statements describe our future plans, objectives, expectations or goals. Although the Company believes that the expectations reflected in such forward-looking statements are reasonable, no assurances can be given that these expectations will prove to be correct. Such statements address future events and conditions and include, but are not limited to:


•	capital expenditures,


•	earnings,


•	liquidity and capital resources,


•	ratemaking/regulatory matters,


•	litigation,


•	accounting matters,


•	possible corporate restructurings, acquisitions and dispositions,


•	compliance with debt and other restrictive covenants,


•	interest rates and dividends,


•	environmental matters,


•	nuclear operations, and


•	the overall economy of our service area.

These forward-looking statements are based on assumptions and analyses in light of the Company's experience and perception of historical trends, current conditions, expected future developments and other factors the Company believes were appropriate in the circumstances when the statements were made. Forward-looking statements by their nature involve substantial risks and uncertainties that could significantly impact expected results, and actual future results could differ materially from those described in such statements. While it is not possible to identify all factors, the Company continues to face many risks and uncertainties. Factors that would cause or contribute to such differences include, but are not limited to:


•	actions of our regulators,


•	our ability to fully and timely recover our costs and earn a reasonable rate of return on our invested capital through the rates that we are permitted to charge,


•	rates, cost recovery mechanisms and other regulatory matters including the ability to recover fuel costs on a timely basis,


•	the ability of 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 new or expanded regulatory or environmental requirements,


•	reductions in output at generation plants operated by us,


•	the size of our construction program and our ability to complete construction on budget and on time,


•	our reliance on significant customers,


•	the credit worthiness of our customers,


•	unscheduled outages of generating units including outages at Palo Verde,


•	changes in customers' demand for electricity as a result of energy efficiency initiatives and emerging competing services and technologies, including distributed generation,


•	individual customer groups, including distributed generation customers, may not pay their full cost of service, and other customers may or may not be required to pay the difference,



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•	changes in, and the assumptions used for, pension and other post-retirement and post-employment benefit liability calculations, as well as actual and assumed investment returns on pension plan and other post-retirement plan assets,


•	the impact of changing cost escalation and other assumptions on our nuclear decommissioning liability for Palo Verde, as well as actual and assumed investment returns on decommissioning trust fund assets,


•	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,


•	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,


•	homeland security considerations, including those associated with the U.S./Mexico border region and the energy industry,


•	changes in environmental laws and regulations and the enforcement or interpretation thereof, including those related to air, water or greenhouse gas ("GHG") emissions or other environmental matters,


•	economic and capital market conditions,


•	changes in accounting requirements and other accounting matters,


•	changing weather trends and the impact of severe weather conditions,


•	possible physical or cyber attacks, intrusions or other catastrophic events,


•	the impact of lawsuits filed against us,


•	the impact of changes in interest rates,


•	Texas, New Mexico and electric industry utility service reliability standards,


•	coal, uranium, natural gas, oil and wholesale electricity prices and availability,


•	possible income tax and interest payments as a result of audit adjustments proposed by the Internal Revenue Service ("IRS") or state taxing authorities,


•	the impact of U.S. health care reform legislation,


•	loss of key personnel, our ability to recruit and retain qualified employees and our ability to successfully implement succession planning, and


•	other circumstances affecting anticipated operations, sales and costs.

These lists are not all-inclusive because it is not possible to predict all factors. A discussion of some of these factors is included in this document under the headings "Risk Factors" and "Management’s Discussion and Analysis" "–Summary of Critical Accounting Policies and Estimates" and "–Liquidity and Capital Resources." This Annual Report on Form 10-K should be read in its entirety. Management cautions against putting undue reliance on forward-looking statements or projecting any future results based on such statements or present or prior earnings levels. Any forward-looking statement speaks only as of the date such statement was made, and 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.



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PART I


Item 1.	Business

General

El Paso Electric Company (the "Company") is a public utility engaged in the generation, transmission and distribution of electricity in an area of approximately 10,000 square miles in west Texas and southern New Mexico. The Company also serves a full requirements wholesale customer in Texas. The Company owns or has significant ownership interests in several electrical generating facilities providing it with a net dependable generating capability of approximately 2,055 MW. For the year ended December 31, 2015, the Company’s energy sources consisted of approximately 47% nuclear fuel, 34% natural gas, 6% coal, 13% purchased power and less than 1% generated by Company-owned solar photovoltaic panels and wind turbines. The Company continues to expand its portfolio of renewable energy sources, particularly solar photovoltaic generation. As of December 31, 2015, the Company has power purchase agreements for 107 MW from solar photovoltaic generation facilities. (See "Energy Sources- Purchased Power").

The Company serves approximately 404,500 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 63% and 12%, respectively, of the Company’s retail revenues for the year ended December 31, 2015). 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 ("White Sands") and Holloman Air Force Base ("HAFB") in New Mexico, an oil refinery, several medical centers, two large universities and a steel production facility.

The Company’s principal offices are located at the Stanton Tower, 100 North Stanton, El Paso, Texas 79901 (telephone 915-543-5711). The Company was incorporated in Texas in 1901. As of January 31, 2016, the Company had approximately 1,100 employees, 38% of whom are covered by a collective bargaining agreement.

The Company makes available free of charge through its website, www.epelectric.com, its Annual Report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, proxy statement, and all amendments to those reports as soon as reasonably practicable after such material is electronically filed with or furnished to the Securities and Exchange Commission ("SEC"). In addition, copies of 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 by reference into this Annual Report.

Facilities

As of December 31, 2015, the Company’s net dependable generating capability of 2,055 MW consists of the following:



Station	Primary Fuel Type	Company's Share of Net Dependable Generating Capability * (MW)	Company Ownership Interest		Location
Newman Power Station	Natural Gas	752	100.0	%	El Paso, Texas
Palo Verde	Nuclear	633	15.8	%	Wintersburg, Arizona
Rio Grande Power Station	Natural Gas	321	100	%	Sunland Park, New Mexico
Montana Power Station (Units 1 and 2)	Natural Gas	176	100	%	El Paso, Texas
Four Corners (Units 4 and 5)	Coal	108	7	%	Fruitland, New Mexico
Copper Power Station	Natural Gas	64	100	%	El Paso, Texas
Renewables	Wind/Solar	1	100	%	Hudspeth/El Paso Counties, Texas; Dona Ana County, New Mexico
Total		2,055

____________________

* During summer peak period, the 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.

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Palo Verde

The Company owns an interest, along with six other utilities, in the three nuclear generating units and common facilities ("Common Facilities") at Palo Verde. Arizona Public Service Company ("APS") serves as operating agent for Palo Verde, and under the Arizona Nuclear Power Project Participation Agreement ("ANPP Participation Agreement"), the Company has limited ability to influence operations and costs at Palo Verde.

•

Palo Verde Operating Licenses. Operation of each of the three Palo Verde Units requires an operating license from the Nuclear Regulatory Commission ("NRC"). The NRC issued full power operating licenses for Unit 1 in June 1985, Unit 2 in April 1986 and Unit 3 in November 1987, and issued renewed operating licenses for each of the three units in April 2011, which extended the licenses for Units 1, 2 and 3 to June 2045, April 2046 and November 2047, respectively.

•

Decommissioning. Pursuant to the ANPP Participation Agreement and federal law, the Company must fund its share of the estimated costs to decommission Palo Verde Units 1, 2 and 3, including the Common Facilities, through the term of their respective operating licenses. In 2013, the Palo Verde Participants approved the 2013 Palo Verde decommissioning study (the "2013 Study"), which estimated that the Company must fund approximately $380.7 million (stated in 2013 dollars) to cover its share of decommissioning costs. At December 31, 2015, the Company's decommissioning trust fund had a balance of $239.0 million. Although the 2013 Study was based on the latest available information, there can be no assurance that decommissioning cost estimates attributable to the Company will not increase in the future or that regulatory requirements will not change.

•

Spent Fuel Storage. Pursuant to the Nuclear Waste Policy Act of 1982, as amended in 1987 (the "NWPA"), the United States Department of Energy ("DOE") is legally obligated to accept and dispose of all spent nuclear fuel and other high-level radioactive waste generated by all domestic power reactors by 1998. The DOE's obligations are reflected in a contract for Disposal of Spent Nuclear Fuel and/or High-Level Radioactive Waste (the "Standard Contract") with each nuclear power plant. The DOE failed to begin accepting spent nuclear fuel by 1998. On December 19, 2012, APS, acting on behalf of itself and the Palo Verde Participants, filed a second breach of contract lawsuit against the DOE. This lawsuit sought to recover damages incurred due to the DOE’s failure to accept Palo Verde’s spent nuclear fuel for the period beginning January 1, 2007 through June 30, 2011. On August 18, 2014, APS and the DOE entered into a settlement agreement, stipulating to a dismissal of the lawsuit and payment of $57.4 million by the DOE to the Palo Verde Participants for certain specified costs incurred by Palo Verde during the period January 1, 2007 through June 30, 2011. On October 8, 2014, the Company received approximately $9.1 million, representing its share of the award. The majority of the award was refunded to customers through the applicable fuel adjustment clauses. On October 31, 2014, APS acting on behalf of itself and the Palo Verde Participants, submitted to the government an additional request for reimbursement of spent nuclear fuel storage costs for the period July 1, 2011 through June 30, 2014. The accepted claim amount was $42.0 million. On June 1, 2015, the Company received approximately $6.6 million, representing its share of the award. The majority of the award was credited to customers through the applicable fuel adjustment clauses in March 2015. Thereafter APS will file annual claims for the period July 1 of the then-previous year to June 30 of the then-current year. On November 2, 2015, APS filed a $12.0 million claim for the period July 1, 2014 through June 30, 2015. In February 2016, the DOE notified APS of the approval of the claim. Funds related to this claim are expected to be received in the second quarter of 2016. The Company's share of this claim is approximately $1.9 million.

•

DOE’s Construction Authorization Application for Yucca Mountain. The DOE had planned to meet its disposal obligations by designing, licensing, constructing and operating a permanent geologic repository 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 U.S. Court of Appeals for the District of Columbia Circuit (the "D.C. Circuit"). In August 2013, the D.C. Circuit ordered the NRC to resume its review of the application with available appropriated funds.

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NRC staff’s finding that the DOE’s repository design meets the requirements that apply after the repository is permanently closed, including but not limited to the post-closure performance objectives in NRC’s regulations.

On December 18, 2014, the NRC issued Volume 4 of the safety evaluation report developed as part of the Yucca Mountain construction authorization application. This volume covers administrative and programmatic requirements for the repository. It documents the NRC staff’s evaluation of whether the DOE’s research and development and performance confirmation programs, as well as other administrative controls and systems, meet applicable NRC requirements. Volume 4 contains the NRC staff’s finding that most administrative and programmatic requirements in NRC regulations are met, except for certain requirements relating to ownership of land and water rights.

Publication of Volumes 3 and 4 does not signal whether or when the NRC might authorize construction of the repository. The Company cannot predict when spent fuel shipments to the DOE will commence.

•

Waste Confidence. On June 8, 2012, the D.C. Circuit issued its decision on a challenge by several states and environmental groups of the NRC’s rulemaking regarding temporary storage and permanent disposal of high level nuclear waste and spent nuclear fuel. The petitioners challenged the NRC’s 2010 update to the agency’s Waste Confidence Decision and temporary storage rule (“Waste Confidence Decision”).

The D.C. Circuit found that the agency’s 2010 Waste Confidence Decision update constituted a major federal action, which, consistent with the National Environmental Policy Act (“NEPA”), requires either an environmental impact statement or a finding of no significant impact from the agency’s actions. The D.C. Circuit found that the NRC’s evaluation of the environmental risks from spent nuclear fuel was deficient, and therefore remanded the 2010 Waste Confidence Decision update for further action consistent with NEPA.

On September 6, 2012, the NRC Commissioners issued a directive to the NRC staff to proceed directly with development of a generic environmental impact statement to support an updated Waste Confidence Decision. The NRC Commissioners also directed the NRC staff to establish a schedule to publish a final rule and environmental impact study within 24 months of September 6, 2012.

In September 2013, the NRC issued its draft Generic Environmental Impact Statement (“GEIS”) to support an updated Waste Confidence Decision. On August 26, 2014, the NRC approved a final rule on the environmental effects of continued storage of spent nuclear fuel. The continued storage rule adopted the findings of the GEIS regarding the environmental impacts of storing spent fuel at any reactor site after the reactor’s licensed period of operations. As a result, those generic impacts do not need to be re-analyzed in the environmental reviews for individual licenses. Although Palo Verde has not been involved in any licensing actions affected by the D.C. Circuit’s June 8, 2012 decision, the NRC lifted its suspension on final licensing actions on all nuclear power plant licenses and renewals that went into effect when the D.C. Circuit issued its June 2012 decision. The August 2014 final rule has been subject to continuing legal challenges before the NRC and the Court of Appeals.

Palo Verde has sufficient capacity at its on-site independent spent fuel storage installation (“ISFSI”) to store all of the nuclear fuel that will be irradiated during the initial operating license period, which ends in December 2027. Additionally, Palo Verde has sufficient capacity at its on-site ISFSI to store a portion of the fuel that will be irradiated during the period of extended operation, which ends in November 2047. If uncertainties regarding the United States government’s obligation to accept and store spent fuel are not favorably resolved, APS will evaluate alternative storage solutions that may obviate the need to expand the ISFSI to accommodate all of the fuel that will be irradiated during the period of extended operation.

•

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.

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but has minor additional work to perform in 2016. Palo Verde has spent approximately $125 million (the Company's share is $19.7 million) on capital enhancements related to these requirements as of December 31, 2015.

•

Liability and Insurance Matters. The Palo Verde Participants have insurance for public liability resulting from nuclear energy hazards, covered by primary liability insurance provided by commercial insurance carriers and an industry-wide retrospective assessment program. If a loss at a nuclear power plant covered by the programs exceeds the accumulated funds in the primary level of protection, the Company could be assessed retrospective premium adjustments on a per incident basis up to $60.4 million, with an annual payment limitation of approximately $9.0 million. The Palo Verde Participants also maintain $2.8 billion of "all risk" nuclear property insurance. The insurance provides coverage for property damage and decontamination at Palo Verde. For covered incidents involving property damage not accompanied by a release of radioactive material, the policy's coverage limit is $2.25 billion. In addition, the Company has secured insurance against portions of any increased cost of generation or purchased power and business interruption resulting from a sudden and unforeseen outage at Palo Verde.

Fossil-Fueled Plants

The Newman Power Station consists of three conventional steam-electric generating units and two combined cycle generating units. The station operates primarily on natural gas but the conventional steam-electric generating units can also operate on fuel oil.

The Company's Rio Grande Power Station consists of three conventional steam-electric generating units and one aeroderivative unit that operate on natural gas.

The Company's Montana Power Station ("MPS") consists of two aeroderivative generating units which operate on natural gas.

The Company's Copper Power Station consists of a natural gas combustion turbine used primarily to meet peak demand.

The Company owns a 7% interest in Units 4 and 5 at Four Corners. The Company shares power entitlements and certain allocated costs of the two units with APS (the Four Corners operating agent) and the other Four Corners participants. Four Corners is a coal-fired generating facility that is located on land under easements from the federal government and a lease from the Navajo Nation that expires in July of 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.

The Company notified the other participants in 2013 that it would not continue in Four Corners after the termination of the 50-year contractual term of the participation agreement in July 2016 but that it would offer to sell its interest to them in order to facilitate their decision to extend the life of the plant. On February 17, 2015, the Company and APS entered into an asset purchase agreement (the "Purchase and Sale Agreement") providing for the purchase by APS of the Company’s interests in Four Corners. The cash purchase price is equal to the net book value of the Company’s interest in Four Corners at the date of closing. The anticipated closing date for the sale is July 6, 2016, pending regulatory approval. The purchase price will be adjusted downward to reflect APS’s assumption in the Agreement of the Company’s obligation to pay for future plant decommissioning and mine reclamation expenses. At the closing, APS will also reimburse the Company for the undepreciated value of certain capital expenditures made prior thereto. APS will assume responsibility for all capital expenditures made after July 2016 and, with certain exceptions, any pre-2016 capital expenditures to be put into service following the closing. In addition, APS will indemnify the Company against liabilities and costs related to the future operation of Four Corners.

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 and Arizona and three 500 kV lines in Arizona. These lines enable the Company to deliver its energy entitlements from its remote generation sources at Palo Verde and Four Corners to its service area (pursuant to various transmission and power exchange agreements to which the Company is a party). The Company also owns the transmission and distribution network within its New Mexico and Texas retail service area and operates these facilities under franchise agreements with various municipalities. Pursuant to standards established by the North American Electric Reliability Corporation and the Western Electricity Coordinating Council, the Company

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operates its transmission system in a way that allows it to maintain system integrity in the event that any one of these transmission lines is out of service.

In addition to the transmission and distribution lines within our service territory, the Company's transmission network and associated substations include the following:



Line	Length (miles)	Voltage (kV)	Company Ownership Interest
Springerville-Macho Springs-Luna-Diablo Line (1)	310	345	100.0	%
West Mesa-Arroyo Line (2)	202	345	100.0	%
Greenlee-Hidalgo-Luna-Newman Line (3)
Greenlee-Hidalgo	60	345	40.0	%
Hidalgo-Luna	50	345	57.2	%
Luna-Newman	86	345	100.0	%
Eddy County-AMRAD Line (4)	125	345	66.7	%
Palo Verde Transmission
Palo Verde-Westwing (5)	45	500	18.7	%
Palo Verde-Jojoba-Kyrene (6)	75	500	18.7	%

____________________


(1)	Runs from Tucson Electric Power Company ("TEP") Springerville Generating Plant near Springerville, Arizona, to the Company's Diablo Substation near Sunland Park, New Mexico.


(2)	Runs from Public Service Company of New Mexico ("PNM") West Mesa Substation located near Albuquerque, New Mexico, to the Company's Arroyo Substation located near Las Cruces, New Mexico.


(3)	Runs from TEP's Greenlee Substation near Duncan, Arizona to the Newman Power Station.

(4) Runs from the Company's and PNM's high voltage direct current terminal at the Eddy County Substation near Artesia, New Mexico to the AMRAD Substation near Oro Grande, New Mexico.


(5)	Represents two 45-mile, 500 kV lines running from Palo Verde to the Westwing Substation located northwest of Phoenix near Peoria, Arizona.

(6) Runs from Palo Verde to the Jojoba Substation located near Gila Bend, Arizona, then to the Kyrene Substation located near Tempe, Arizona.

Environmental Matters

The Company is subject to extensive laws, regulations and permit requirements with respect to air and GHG emissions, water discharges, soil and water quality, waste management and disposal, natural resources and other environmental matters by federal, state, regional, tribal and local authorities. Failure to comply with such laws, regulations and requirements can result in actions by authorities or other third parties that might seek to impose on the Company administrative, civil and/or criminal penalties or other sanctions. In addition, releases of pollutants or contaminants into the environment can result in costly cleanup liabilities. These laws, regulations and requirements are subject to change through modification or reinterpretation, or the introduction of new laws and regulations and, as a result, the Company may face additional capital and operating costs to comply.

See Part II, Item 8, Financial Statements and Supplementary Data, Note K for more information regarding environmental risks, laws and regulations and legal proceedings for which we are and maybe subject to in the future.

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 2016 through 2020 are approximately $1.1 billion. Actual costs may vary from the construction program estimates shown. Such estimates are reviewed and updated periodically to reflect changed conditions.

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By Year (1)(2) (estimates in millions)			By Function (estimates in millions)
2016	$	231	Production (1)(2)	$	534
2017	156		Transmission	113
2018	182		Distribution	323
2019	232		General	114
2020	283
Total	$	1,084	Total	$	1,084

__________________________


(1)	Does not include acquisition costs for nuclear fuel. See "Energy Sources – Nuclear Fuel."


(2)	Estimated production costs consist of:


a.	$307 million for new generating capacity, including:


i.	$32 million for MPS of which $25 million is to complete construction of two 88 MW gas-fired LMS-100 units (3 and 4) that are scheduled to come on line in May and December of 2016, respectively.


ii.	$254 million of construction costs from 2018 through 2020 for two combined cycle units scheduled to be completed in 2022 and 2024.


iii.	$21 million for two utility-scale solar energy generating facilities, which would have a combined maximum capacity up to 8 MW.


b.	$227 million of other generation costs, including $189 million for Palo Verde.

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Energy Sources

General

The following table summarizes the percentage contribution of nuclear fuel, natural gas, coal and purchased power to the total kWh energy mix of the Company. Energy generated by Company-owned solar photovoltaic panels and wind turbines accounted for less than 1% of the total kWh energy mix.



	Years Ended December 31,
	2015		2014		2013
Power Source	(percentage of energy mix)
Nuclear	47	%	47	%	46	%
Natural gas	34		35		34
Coal	6		5		6
Purchased power	13		13		14
Total	100	%	100	%	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 and conversion services through 2018 and 45% of its requirements in 2019-2021. The participants have also contracted for 100% of Palo Verde's enrichment services through 2020 and all of Palo Verde's fuel assembly fabrication services through 2022.

Nuclear Fuel Financing. The Company’s financing of nuclear fuel is accomplished through Rio Grande Resources Trust ("RGRT"), a Texas grantor trust, which is consolidated in the Company’s financial statements. RGRT has $95 million aggregate principal amount borrowed in the form of senior notes. The Company guarantees the payment of principal and interest on the senior notes. The nuclear fuel financing requirements of RGRT are met with a combination of the senior notes and short-term borrowings under the revolving credit facility (the "RCF").

Natural Gas

The Company manages its natural gas requirements through a combination of a long-term (greater than a year) supply contract, several medium-term (greater than a month but less than one year) supply contracts and spot or short-term (daily to a month) market purchases. The long-term supply contract provides for firm deliveries of gas at market-based index prices. Medium-term and spot agreements are either fixed priced and/or index priced depending on the market. In 2015, the Company’s natural gas requirements at the Newman, Rio Grande and MPS were met with short-term, medium-term and long-term natural gas purchases from various suppliers, and this practice is expected to continue in 2016. Interstate gas is delivered under a base firm transportation contract. The Company has expanded its firm interstate transportation contract to include MPS. The Company anticipates it will continue to purchase natural gas at spot market prices on a monthly basis for a portion of the fuel needs for Newman, Rio Grande and MPS. The Company will continue to evaluate the availability of short-term natural gas supplies versus medium and long-term supplies to maintain a reliable and economical supply for its local generating stations.

Natural gas for the Newman and Copper Power Stations is also supplied pursuant to a long-term intrastate natural gas contract that became effective October 1, 2009 and continues through 2017.

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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 Company notified the other participants in 2013 that it would not continue in Four Corners after the termination of the 50-year contractual term of the participation agreement in July 2016 but that it would offer to sell its interest to them in order to facilitate their decision to extend the life of the plant. On February 17, 2015, the Company and APS entered into the Purchase and Sale Agreement providing for the purchase by APS of the Company’s interests in Four Corners. The cash purchase price is equal to the net book value of the Company’s interest in Four Corners at the date of closing. The anticipated closing date for the sale is July 6, 2016, pending regulatory approval. The purchase price will be adjusted downward to reflect APS’s assumption in the Agreement of the Company’s obligation to pay for future plant decommissioning and mine reclamation expenses. At the closing, APS will also reimburse the Company for the undepreciated value of certain capital expenditures made prior thereto. APS will assume responsibility for all capital expenditures made after July 2016 and, with certain exceptions, any pre-2016 capital expenditures to be put into service following the closing. In addition, APS will indemnify the Company against liabilities and costs related to the future operation of Four Corners.

Purchased Power

To supplement its own generation and operating reserve requirements, and to meet required renewable portfolio standards, the Company engages in power purchase arrangements that may vary in duration and amount based on an evaluation of the Company’s resource needs, the economics of the transactions and specific renewable portfolio requirements.

The Company has a firm 100 MW Power Purchase and Sale Agreement with Freeport-McMoran Copper and Gold Energy Services LLC ("Freeport") that provides for Freeport to deliver energy to the Company from the Luna Energy Facility (a natural gas-fired combined cycle generation facility located in Luna County, New Mexico) and for the Company to deliver a like amount of energy at Greenlee, Arizona. The Company may purchase up to the contracted MW amount at a specified price at times when energy is not exchanged under the Power Purchase and Sale Agreement. The agreement was approved by the Federal Energy Regulatory Commission ("FERC") and will continue through an initial term ending December 31, 2021, with subsequent rollovers until terminated. Upon mutual agreement, the Power Purchase and Sale Agreement allows the parties to increase the amount of energy that is purchased and sold under the agreement. The parties have agreed to increase the amount to 125 MW through December 2016.

The Company has entered into several power purchase agreements to help meet its renewable portfolio requirements. Specifically, the Company has a 25-year purchase power agreement with Hatch Solar Energy Center I, LLC for a 5 MW solar photovoltaic project located in southern New Mexico, which began commercial operation in July 2011. In June 2015, the Company entered into a consent agreement with Hatch Solar Energy Center 1, LLC to provide for additional or replacement photovoltaic modules. The Company also entered into a 20-year contract with NRG Solar Roadrunner, LLC ("NRG") for the purchase of all of the output of a 20 MW solar photovoltaic plant built in southern New Mexico, which began commercial operation in August 2011. In addition, the Company has 25-year purchase power agreements to purchase all of the output of two additional solar photovoltaic projects located in southern New Mexico, SunE EPE1, LLC (10 MW) and SunE EPE2, LLC (12 MW), which began commercial operation in June 2012 and May 2012, respectively.

Furthermore, the Company has a 20-year purchase power agreement with Macho Springs Solar, LLC to purchase the entire generation output delivered from the 50 MW Macho Springs solar photovoltaic project located in Luna County, New Mexico which began commercial operation in May 2014. Finally, the Company has a 30-year purchase power agreement with Newman Solar LLC to purchase the total output of approximately 10 MW from a solar photovoltaic generation plant on land subleased from the Company in proximity to its Newman Generation Station. This solar project began commercial operation in December 2014.

Other purchases of shorter duration were made during 2015 to supplement the Company's generation resources during planned and unplanned outages, for economic reasons, and to supply off-system sales.

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Operating Statistics



	Years Ended December 31,
	2015			2014		2013
Operating revenues (in thousands):
Non-fuel base revenues:
Retail:
Residential	$	246,265		$	234,371	$	236,651
Commercial and industrial, small	187,436			185,388		184,568
Commercial and industrial, large	40,411			39,239		40,235
Sales to public authorities	91,244			92,066		95,044
Total retail base revenues	565,356			551,064		556,498
Wholesale:
Sales for resale	2,455			2,277		2,172
Total non-fuel base revenues	567,811			553,341		558,670
Fuel revenues:
Recovered from customers during the period	127,765			161,052		133,481
Under (over) collection of fuel	(13,342		)	3,110		10,849
New Mexico fuel in base rates	72,129			71,614		73,295
Total fuel revenues	186,552			235,776		217,625
Off-system sales:
Fuel cost	52,406			74,716		68,241
Shared margins	11,048			21,117		13,016
Retained margins	1,362			2,147		1,549
Total off-system sales	64,816			97,980		82,806
Other	30,690			30,428		31,261
Total operating revenues	$	849,869		$	917,525	$	890,362
Number of customers (end of year) (1):
Residential	358,819			353,885		349,629
Commercial and industrial, small	40,367			40,038		39,164
Commercial and industrial, large	49			49		50
Other	5,261			5,017		5,043
Total	404,496			398,989		393,886
Average annual kWh use per residential customer	7,763			7,496		7,701
Energy supplied, net, kWh (in thousands):
Generated	9,585,089			9,477,129		9,288,773
Purchased and interchanged	1,390,946			1,390,490		1,547,930
Total	10,976,035			10,867,619		10,836,703
Energy sales, kWh (in thousands):
Retail:
Residential	2,771,138			2,640,535		2,679,262
Commercial and industrial, small	2,384,514			2,357,846		2,349,148
Commercial and industrial, large	1,062,662			1,064,475		1,095,379
Sales to public authorities	1,585,568			1,562,784		1,622,607
Total retail	7,803,882			7,625,640		7,746,396
Wholesale:
Sales for resale	63,347			61,729		61,232
Off-system sales	2,500,947			2,609,769		2,472,622
Total wholesale	2,564,294			2,671,498		2,533,854
Total energy sales	10,368,176			10,297,138		10,280,250
Losses and Company use	607,859			570,481		556,453
Total	10,976,035			10,867,619		10,836,703
Native system:
Peak load, kW	1,794,000			1,766,000		1,750,000
Net dependable generating capability for peak, kW	2,055,000			1,879,000		1,852,000
Total system:
Peak load, kW (2)	1,992,000			1,953,000		1,883,000
Net dependable generating capability for peak, kW	2,055,000			1,879,000		1,852,000

___________________________


(1)	The number of retail customers presented is based on the number of service locations.


(2)	Includes spot sales and net losses of 198,000 kW, 187,000 kW and 133,000 kW for 2015, 2014 and 2013, respectively.

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Regulation

General

The rates and services of the Company are regulated by incorporated municipalities in Texas, the PUCT, the NMPRC and the FERC. Municipal orders, ordinances and other agreements regarding rates and services adopted by Texas municipalities are subject to review and approval by the PUCT. The FERC has jurisdiction over the Company's wholesale (sales for resale) transactions, 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. On April 17, 2012, the El Paso City 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 and the rates were effective as of May 1, 2012. As part of the 2012 Texas retail rate settlement, the Company agreed to 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 Company filed a fuel reconciliation request covering the period July 1, 2009 through March 31, 2013, as discussed below. The 2012 Texas retail rate settlement also provided 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.

2015 Texas Retail Rate Case Filing. On August 10, 2015, the Company filed with the City of El Paso, other municipalities incorporated in its Texas service territory, and the PUCT in Docket No. 44941, a request for an increase in non-fuel base revenues of approximately $71.5 million. The request includes recovery of new plant placed into service since 2009 . On January 15, 2016, the Company filed its rebuttal testimony modifying the requested increase to $63.3 million. The Company has invoked its statutory right to have its new rates relate back for consumption on and after January 12, 2016, which is the 155th day after the filing. The difference in rates that would have been collected will be surcharged or refunded to customers beginning after the PUCT's final order in Docket No. 44941, which is expected to be in the second quarter of 2016. The PUCT has the authority to require the Company to surcharge or refund such difference over a period not to exceed 18 months. On January 21, 2016, the Company, the City of El Paso, the PUCT staff, the Office of Public Utility Counsel and the Texas Industrial Energy Consumers filed a joint motion to abate the procedural schedule to facilitate settlement talks. This motion was granted. The Company cannot predict the outcome of the rate case at this time.

Energy Efficiency Cost Recovery Factor. The Company made its annual filing to establish its energy efficiency cost recovery factor for 2015 on May 1, 2014. In addition to projected energy efficiency costs for 2015 and true-up to prior year actual costs, the Company requested approval of a $2.0 million bonus for the 2013 energy efficiency program results in accordance with PUCT rules. The PUCT approved the Company's request at its November 14, 2014 open meeting. The Company recorded the $2.0 million bonus as operating revenue in the fourth quarter of 2014.

On May 1, 2015, the Company made its annual filing to establish its energy efficiency cost recovery factor for 2016. In addition to projected energy efficiency costs for 2016 and true-up to prior year actual costs, the Company requested approval of a $1.0 million bonus for the 2014 energy efficiency program results in accordance with PUCT rules. This case was assigned PUCT Docket No. 44677. A stipulation and settlement agreement was filed September 24, 2015 and the PUCT approved the settlement on November 5, 2015. The settlement approved by the PUCT includes a performance bonus of $1.0 million. The Company recorded the performance bonus as operating revenue in the fourth quarter of 2015.

Fuel and Purchased Power Costs. The Company's actual fuel costs, including purchased power energy costs, are recovered from customers through a fixed fuel factor. The PUCT has adopted a fuel cost recovery rule (the "Texas Fuel Rule") that allows the Company to seek periodic adjustments to its fixed fuel factor. The Company can seek to revise its fixed fuel factor based upon the approved formula at least four months after its last revision except in the month of December. The Texas Fuel Rule requires the Company to request to refund fuel costs in any month when the over-recovery balance exceeds a threshold material amount and it expects fuel costs to continue to be materially over-recovered. The Texas Fuel Rule also permits the Company to seek to surcharge fuel under-recoveries in any month the balance exceeds a threshold material amount and it expects fuel cost recovery to continue to be materially under-recovered. Fuel over and under-recoveries are considered material when they exceed 4% of the previous twelve months' fuel costs. All such fuel revenue and expense activities are subject to periodic final review by the PUCT in fuel reconciliation proceedings.

On April 15, 2015, the Company filed a request, which was assigned PUCT Docket No. 44633, to reduce its fixed fuel factor by approximately 24% to reflect an expected reduction in fuel expense. The over-recovered balance was below the PUCT's materiality threshold. The reduction in the fixed fuel factor was effective on an interim basis May 1, 2015 and approved by the

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PUCT on May 20, 2015. As of December 31, 2015, the Company had over-recovered fuel costs in the amount of $0.1 million for the Texas jurisdiction.

Fuel Reconciliation Proceeding. Pursuant to the 2012 Texas retail rate settlement discussed above, on September 27, 2013, the Company filed an application with the PUCT, designated as PUCT 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. A settlement was reached and a final order was issued by the PUCT on July 11, 2014. The PUCT's final order completes the regulatory review and reconciliation of the Company's fuel expenses for the period through March 31, 2013. The Company is required to file an application in 2016 for fuel reconciliation of the Company’s fuel expenses for the period through March 31, 2016.

Montana Power Station Approvals. The Company has received a Certificate of Convenience and Necessity ("CCN") from the PUCT to construct four natural gas fired generating units at MPS in El Paso County, Texas. The Company also obtained air permits from the Texas Commission on Environmental Quality (the "TCEQ") and the U.S. Environmental Protection Agency (the "EPA"). MPS Units 1 and 2 and associated transmission lines and common facilities were completed and placed into service in March 2015.

Community Solar. On June 8, 2015, the Company filed a petition with the PUCT to initiate a community solar program to include construction and ownership of a 3 MW solar photovoltaic system located at MPS. Participation will be on a voluntary basis, and customers will contract for a set capacity (kW) amount and receive all energy produced. This case was assigned PUCT Docket No. 44800. The Company presented the other parties a proposed structure for settlement of this proceeding and the other parties are in the process of evaluating it.

Four Corners. On February 17, 2015, the Company and APS entered into the Purchase and Sale Agreement providing for the purchase by APS of the Company's interests in Four Corners. The Purchase and Sale Agreement included a projected cash purchase price which will be equal to the net book value of our interest in Four Corners at the date of close. The net book value at June 30, 2016 is expected to approximate $20 million. The Company will also be reimbursed for certain undepreciated capital expenditures, that are projected to approximate $10 million at June 30, 2016. The purchase price will be adjusted downward to reflect APS's assumption of the Company's obligation to pay for future plant decommissioning and mine reclamation expenses estimated at July 6, 2016 to be $7.0 million and $19.3 million, respectively.

On June 10, 2015, the Company filed an application in Texas requesting reasonableness and public interest findings and certain rate and accounting findings related to the Purchase and Sale Agreement. The anticipated closing date of the sale is July 6, 2016, pending regulatory approval. This case was assigned PUCT Docket No. 44805. It is expected that the final coal mine closing and reclamation costs, which the Company historically has been permitted to recover in its fuel recovery mechanism, will be addressed in the proceeding, as well as other issues related to post-participation events such as the ARO. On January 11, 2016, the PUCT referred the case to the State Office of Administrative Hearings ("SOAH") for an administrative hearing. On February 5, 2016, an administrative law judge ("ALJ") of the SOAH issued an order adopting a procedural schedule. The procedural schedule calls for a hearing on the merits to be held in the fourth quarter of 2016. At December 31, 2015 the regulatory asset associated with mine reclamation costs for our Texas jurisdiction approximates $7.6 million. At the PUCT's February 11, 2016 open meeting, Commissioners discussed whether the Company's application should be addressed in a rate case. On February 11, 2016, the PUCT issued its Order Requesting Briefing on Threshold Legal/Policy Issues, seeking briefs from the parties on the issue "Should the Commission dismiss this docket?" Such briefs were due by February 22, 2016. The PUCT is expected to consider that issue at its open meeting currently scheduled for March 3, 2016.

The Company currently continues to recover its mine reclamation costs in Texas under previous orders and decisions of the PUCT. If any future determinations made by our regulators result in changes to how existing regulatory assets or previously incurred costs for Four Corners are recovered in rates, any such changes would be recognized only when it becomes probable future cash flows will change as a result of such regulatory actions.

Other Required Approvals. The Company has obtained other required approvals for tariffs and approvals 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 are updated annually for adjustment to the recovery factors.

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plant placed into service since the last time rates were adjusted in 2009. The filing also requests an annual reduction of $15.4 million, or 21.5%, for fuel and purchased power costs recovered in base rates. The reduction in fuel and purchased power rates reflects reduced fuel prices and improvements in system heat rates due to new generating unit additions. Subsequently, the Company reduced its requested increase in non-fuel base rates to approximately $6.4 million On February 16, 2016, the Hearing Examiner issued a Recommended Decision to the NMPRC proposing an annual increase in non-fuel base rates of approximately $640 thousand. On February 17, 2016, the NMPRC issued an order extending the suspension period in the rate case from March 10, 2016 until April 8, 2016, by which time the NMPRC is expected to either issue a final order with new rates to go into effect in the second quarter of 2016 or again extend the suspension period further to as late as June 10, 2016. All parties will be allowed to file exceptions before the NMPRC ultimately rules on the issues by final order. The Company cannot predict the outcome of the rate case at this time.

Fuel and Purchased Power Costs. Fuel and purchased power costs are recovered through base rates and a Fuel and Purchased Power Cost Adjustment Clause (the "FPPCAC") that accounts for changes in the costs of fuel relative to the amount included in base rates. On January 8, 2014, the NMPRC approved the continuation of the FPPCAC without modification in NMPRC Case No. 13-00380-UT. Fuel and purchased power costs are reconciled to actual costs on a monthly basis and recovered or refunded to customers the second succeeding month. The Company recovers costs related to Palo Verde Unit 3 capacity and energy in New Mexico through the FPPCAC as purchased power using a proxy market price approved in the 2014 FPPCAC continuation. At December 31, 2015, we had a net fuel over-recovery balance of $3.8 million in New Mexico.

Montana Power Station Approvals. The Company has received a CCN from the NMPRC to construct four units at MPS and the associated transmission lines. The Company also obtained all necessary air permits from the TCEQ and the EPA. A final order in NMPRC Case No. 13-00297-UT approving the CCN for MPS Units 3 and 4 was issued on June 11, 2014. MPS Units 1 and 2 and MPS to Caliente and MPS In & Out transmission lines were completed and placed into service in March 2015.

Four Corners Generating Station ("Four Corners"). On February 17, 2015, the Company and APS entered into the Purchase and Sale Agreement providing for the purchase by APS of the Company's interests in Four Corners. On April 27, 2015, the Company filed an application requesting all necessary regulatory approvals to sell its ownership interest in Four Corners. The anticipated closing date of the sale is July 6, 2016, pending regulatory approval. This case was assigned NMPRC Case No. 15-00109-UT. On February 2, 2016, the Company filed a joint stipulation with the NMPRC reflecting a settlement agreement among the Commission Utility Division Staff, the Company and the New Mexico Attorney General proposing approval of abandonment and sale of its seven percent minority ownership interest in Four Corners Units 4 and 5 and common facilities to APS. An addendum to the joint stipulation was subsequently filed to include non-opposition by other non-stipulating parties. A hearing in the case was held on February 16, 2016, and a final order approving the joint stipulation is expected in the first half of 2016. Based on the joint stipulation and addendum, no significant gain or loss is expected to be realized upon closing of the sale.

5 MW HAFB Facility CCN. On June 15, 2015, the Company filed a petition with the NMPRC requesting CCN authorization to construct a 5 MW solar-powered generation facility to be located at HAFB in the Company's service territory in New Mexico. The new facility will be a dedicated Company-owned resource serving HAFB. This case was assigned NMPRC Case No. 15-00185-UT. On October 7, 2015, the NMPRC issued a Final Order accepting the Hearing Examiner’s Recommended Decision to approve the CCN, as modified, that the Company shall not seek to recover any revenue requirement associated with the facility from New Mexico jurisdictional customers other than HAFB without prior NMPRC approval.

Issuance of Long-Term Debt and Guarantee of Debt. On October 7, 2015 the Company received approval in NMPRC Case No. 15-00280-UT to issue up to $310 million in new long-term debt; and to guarantee the issuance of up to $65 million of new debt by RGRT to finance future purchases of nuclear fuel and to refinance existing nuclear fuel debt obligations. This approval supersedes prior approvals.

Other Required Approvals. The Company has obtained other required approvals for other tariffs, securities transactions, recovery of energy efficiency costs through a base rate rider and other approvals as required by the NMPRC.

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Federal Regulatory Matters

Four Corners. On June 26, 2015, APS filed an application requesting authorization from FERC to purchase 100% of the Company’s ownership interest in Units 4 and 5 of Four Corners and the associated transmission interconnection facilities and rights. On December 22, 2015, FERC issued an order approving the proposed transaction.

PNM Transmission Rate Case. On December 31, 2012, PNM filed with FERC to change its method of transmission rate recovery for its transmission delivery services from stated rates to formula rates. The Company takes transmission service from PNM and is among the PNM transmission customers affected by PNM’s shift to formula rates. On March 1, 2013, the FERC issued an order rejecting in part PNM’s filing, and establishing settlement judge and hearing procedures. On March 20, 2015, PNM filed with FERC a settlement agreement and offer of settlement resolving all issues set for hearing in the proceeding. On March 25, 2015, the Chief Judge issued an order granting PNM's motion to implement the settled rates. However, the Company is still awaiting a final decision from the FERC on whether the settlement will be approved. The Company cannot predict the outcome of the case at this time.

Revolving Credit Facility; Issuance of Long-Term Debt and Guarantee of Debt. On October 19, 2015, the FERC issued an order in Docket No. ES15-66-000 approving the Company’s filing to issue short-term debt under its existing revolving credit facility up to $400 million outstanding at any time, to issue up to $310 million in long-term debt, and to guarantee the issuance of up to $65 million of new long-term debt by RGRT to finance future nuclear fuel purchases. The authorization is effective from November 15, 2015 through November 15, 2017. This approval supersedes prior approvals.

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. The DOE regulates the Company's exports of power to the Comisión Federal de Electricidad in Mexico pursuant to a license and two presidential permits issued by the DOE.

The DOE is authorized to assess operators of nuclear generating facilities a share of the costs of decommissioning the DOE's uranium enrichment facilities and for the ultimate costs of disposal of spent nuclear fuel. See Facilities-Palo Verde for discussion of spent fuel storage and disposal costs.

Sales for Resale

The Company provides firm capacity and associated energy to the Rio Grande Electric Cooperative ("RGEC") pursuant to an ongoing contract with a two-year notice to terminate provision. The Company also provides network integrated transmission service to the RGEC pursuant to the Company's Open Access Transmission Tariff ("OATT"). The contract includes a formula-based rate that is updated annually to recover non-fuel generation costs and a fuel adjustment clause designed to recover all eligible fuel and purchased power costs allocable to the RGEC.

Power Sales Contracts

The Company has entered into several short-term (three months or less) off-system sales contracts throughout 2015.

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Franchises and Significant Customers

Franchises

The Company operates under franchise agreements with several cities in its service territory, including one with El Paso, the largest city it serves. The franchise agreement allows the Company to utilize public rights-of-way necessary to serve its customers within El Paso. Pursuant to the El Paso franchise agreement amended in 2010, the Company pays to the City of El Paso, on a quarterly basis, a fee equal to 4.00% of gross revenues the Company receives for the generation, transmission and distribution of electrical energy and other services within the city. The 2005 El Paso franchise agreement set the franchise fee at 3.25% of gross revenues, but the 2010 Amendment added an incremental fee equal to 0.75% of gross revenues to be placed in a restricted fund to be used by the city solely for economic development and renewable energy purposes. Any assignment of the franchise agreement, including a deemed assignment as a result of a change in control of the Company, requires the consent of the City of El Paso. The El Paso franchise agreement is set to expire on July 31, 2030.

The Company does not have a written franchise agreement with the City of Las Cruces, the second largest city in its service territory. The Company provides electric distribution service to Las Cruces under an implied franchise by satisfying all obligations under the franchise agreement that expired on April 30, 2009. The Company pays the City of Las Cruces a franchise fee of 2.00% of gross revenues the Company receives from services within the City of Las Cruces.

Military Installations

The Company serves HAFB, White Sands and Fort Bliss. The military installations represent approximately 4% of the Company's annual retail revenues. In July 2014, the Company signed an agreement with Fort Bliss for an initial three-year term under which Fort Bliss takes retail electric service from the Company under the applicable Texas tariffs. The Company serves White Sands under the applicable New Mexico tariffs. In March 2006, the Company signed a contract with HAFB under which the Company provides retail electric service and limited wheeling services to HAFB for a ten-year term which expired in January 2016 HAFB and the Company agreed to extend the retail pricing provisions of the existing agreement during negotiations for a replacement contract. The contract was revised to include to allow for an extension of services under the existing agreement.

Other Information

Investors should note that we announce material financial information in our filings with the SEC, press releases and public conference calls. Based on guidance from the SEC, we may also use the Investor Relations section of our website (www.epelectric.com) to communicate with investors about the Company. It is possible that the financial information we post there could be deemed to be material information. The information contained on or accessible from our website is not incorporated by reference into and does not constitute a part of this Annual Report on Form 10-K.

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Item 1A. Risk Factors

Like other companies in our industry, our financial results are impacted by weather, the economy of our service territory, market prices for power, fuel prices, and the decisions of regulatory agencies. Our common stock price and creditworthiness will be affected by local, regional and national macroeconomic trends, general market conditions and the expectations of the investment community, all of which are largely beyond our control. In addition, the following statements highlight risk factors that may affect our financial condition and results of operations. These are not intended to be an exhaustive discussion of all such risks, and the statements below must be read together with factors discussed elsewhere in this document and in our other filings with the SEC.

Our Revenues and Profitability Depend Upon Regulated Rates

Our retail rates are subject to regulation by incorporated municipalities in Texas, the PUCT, the NMPRC and the FERC. The settlement approved in the Company's 2012 Texas rate case, PUCT Docket No. 40094, established the Company's current retail base rates in Texas, effective May 1, 2012. In addition, the settlement in the Company's 2009 New Mexico rate case, NMPRC Case No. 09‑00171‑UT, established rates in New Mexico that became effective in 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 costs associated with future plant retirement and ARO. 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.

On May 11, 2015 and August 10, 2015, the Company filed a general rate case with the NMPRC, Case No. 15-00127-UT (the “2015 New Mexico rate case”) and the PUCT, Docket No. 44941 (the “2015 Texas rate case”), respectively, to establish new rates and to request recovery of new plant placed into service since 2009. Third parties have intervened in both rate cases and have challenged whether certain of our costs are reasonable and necessary. The Company anticipates a resolution of both the 2015 New Mexico rate case and the 2015 Texas rate case in the first or second quarter of 2016. If the NMPRC and PUCT do not increase the Company’s rates adequately, the Company’s future operations, cash flow and financial condition could be materially adversely affected. For a full discussion of these rate cases see Part II, Item 8, Financial Statements and Supplementary Data, Note C.

We May Not Be Able To Recover All Costs of New Generation and Transmission Assets

In 2013 and 2014, we received approval, both from the PUCT and the NMPRC, to construct four 88 MW simple-cycle aeroderivative combustion turbines at our MPS, a new plant site. 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 2015, we completed construction of MPS Units 1 and 2 which began commercial operation in March 2015. We have risk related to recovering all costs associated with the construction of Rio Grande Unit 9, MPS, and other new units and transmission assets.

In 2014, we issued $150 million in aggregate principal amount of 5.00% Senior Notes, due December 1, 2044. The net proceeds from the 5.00% Senior Notes along with borrowings under our RCF were used to fund the construction of MPS and other capital additions. The costs of financing and constructing these assets are being reviewed in the current Texas and New Mexico rate cases. To the extent that the PUCT or the NMPRC determines that the costs of construction are not reasonable because of cost overruns, delays or other reasons, we may not be allowed to recover these costs from customers in base rates.

In addition, if future units, such as MPS Units 3 and 4 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.

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Weakness in the Economy and Uncertainty in the Financial Markets Could Reduce Our Sales, Hinder Our Capital Programs and Increase Our Funding Obligations for Pensions and Decommissioning

In recent years, the global credit and equity markets and the overall economy have been extremely volatile. These and future events could have a number of effects on our operations and capital programs. For example, tight credit and capital markets could make it difficult and more expensive to raise capital to fund our operations and capital programs. If we are unable to access the credit markets, we could be required to defer or eliminate important capital projects in the future. In addition, declines in the stock market performance may reduce the value of our financial assets and decommissioning trust investments. Such market results may also increase our funding obligations for our pension plans, other post-retirement benefit plans and nuclear decommissioning trusts. Changes in the corporate interest rates that we use as the discount rate to determine our pension and other post-retirement liabilities may have an impact on our funding obligations for such plans and trusts. Further, continued economic volatility may result in reduced customer demand, both in the retail and wholesale markets, and increases in customer delinquencies and write-offs. Uncertainty in the credit markets may negatively impact the ability of our customers to finance purchases of our services and could adversely affect the collectability of our receivables. Similarly, actions or inaction of Congress and of governmental agencies can impact our operations. For example, during 2013, sales to public authorities and small commercial and industrial customers were negatively impacted by the federal government sequestration and shutdown. The credit markets and overall economy may also adversely impact the financial health of our suppliers. If that were to occur, our access to and prices for inventory, supplies and capital equipment could be adversely affected. Our power trading counterparties could also be adversely impacted by the market and economic conditions which could result in reduced wholesale power sales or increased counterparty credit risk. Declines in revenues, earnings and cash flow from these events, could impact our ability to fund construction expenditures and impact the level of dividend payments.

There are Inherent Risks in the Ownership of Nuclear Facilities

Our 15.8% ownership interest in Palo Verde, which is the largest nuclear electric generating facility in the United States, subject us to a number of risks. A significant percentage of our generating capacity, off-system sales margins, assets and operating expenses is attributable to Palo Verde. Our interest in each of the three Palo Verde units totals approximately 633 MW of generating capacity. Palo Verde represents approximately 31% of our available net generating capacity and provided approximately 47% of our energy requirements for the twelve months ended December 31, 2015. Palo Verde comprises approximately 27% 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 94.3% and 93.7% in the twelve months ended December 31, 2015 and 2014, respectively.

As Palo Verde is a nuclear electric generating facility it is subject to environmental, health and financial risks, such as the ability to obtain adequate supplies of nuclear fuel; the ability to dispose of spent nuclear fuel; the ability to maintain adequate reserves for decommissioning; potential liabilities arising out of the operation of these facilities; the costs of securing the facilities against possible terrorist attacks; cyber attacks, or other causes; and unscheduled outages due to equipment and other problems. If a nuclear incident were to occur at Palo Verde, it could materially and adversely affect our results of operations and financial condition. A major incident at a nuclear facility anywhere in the world could cause regulatory bodies to limit or prohibit the operation or licensing of any domestic nuclear unit and to promulgate new regulations that could require significant capital expenditures and/or increase operating costs.

We May Not Be Able to Recover All of Our Fuel Expenses from Customers On a Timely Basis Or at All

In general, by law, we are entitled to recover our reasonable and necessary fuel and purchased power expenses from our customers in Texas and New Mexico. NMPRC Case No. 13-00380-UT provides for energy delivered to New Mexico customers from the deregulated Palo Verde Unit 3 to be recovered through fuel and purchased power costs based upon a previous purchased power contract. Fuel and purchased power expenses in 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 the event that recovery of fuel and purchased power expenses is denied in any reconciliation proceeding, the amounts recorded for fuel and purchased power expenses could differ from the amounts we are allowed to collect from our customers, and we would incur a loss to the extent of the disallowance.

In New Mexico, the 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

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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.

Equipment Failures and Other External Factors Can Adversely Affect Our Results

The generation and transmission of electricity require the use of expensive and complex equipment. While we have a maintenance program in place, generating plants are subject to unplanned outages because of equipment failure and severe weather conditions. The advanced age of several of our gas-fired generating units in or near El Paso increases the vulnerability of these units. In the event of unplanned outages, we must acquire power from other sources at unpredictable costs in order to supply our customers and comply with our contractual agreements. This additional purchased power cost would be subject to review and approval of the PUCT and the NMPRC in reconciliation proceedings. As noted above, in the event that recovery for fuel and purchased power expenses could differ from the amounts we are allowed to collect from our customers, we would incur a loss to the extent of the disallowance. This could materially increase our costs and prevent us from selling excess power at wholesale. In addition, actions of other utilities may adversely affect our ability to use transmission lines to deliver or import power, thus subjecting us to unexpected expenses or to the cost and uncertainty of public policy initiatives. We may also incur additional capital and operating costs in connection with the physical security and cyber security of transmission lines and generation facilities. Damage to certain transmission and generation facilities due to vandalism or other deliberate acts, or damage due to severe weather could lead to outages or other adverse effects. We are particularly vulnerable to this because a significant portion of our available energy (at Palo Verde 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 could 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 have access to, in varying degrees, alternative sources of power, including co-generation of electric power. Deregulation legislation is in effect in Texas requiring us to separate our transmission and distribution functions, which would remain regulated, from our power generation and energy services businesses, which would operate in a competitive market, in the future. In 2004, the PUCT approved a rule delaying retail competition in our Texas service territory. This rule was codified in the PURA in June 2011. The PURA identifies various milestones that we must reach before retail competition can begin. The first milestone calls for the development, approval by the FERC, and commencement of independent operation of a regional transmission organization in the area that includes our service territory. This and other milestones are not likely to be achieved for a number of years, if at all. There is substantial uncertainty about both the regulatory framework and market conditions that would exist if and when retail competition is implemented in our Texas service territory, and we may incur substantial preparatory, restructuring and other costs that may not ultimately be recoverable. There can be no assurance that deregulation would not adversely affect our future operations, cash flow and financial condition.

Future Costs of Compliance with Environmental Laws and Regulations Could

Adversely Affect Our Operations and Financial Results

We are subject to extensive federal, state and local environmental laws and regulations relating to discharges into the air, air quality, discharges of effluents into water, water quality, the use of water, the handling, disposal and clean-up of hazardous and non-hazardous substances and wastes, natural resources, and health and safety. Compliance with these legal requirements, which change frequently and often become more restrictive, could require us to commit significant capital and operating resources toward permitting, emission fees, environmental monitoring, installation and operation of pollution control equipment and purchases of air emission allowances and/or offsets. These laws and regulations could also result in limitations in operating hours and/or changes in construction schedules for future generating units.

Cost of compliance with environmental laws and regulations or fines or penalties resulting from non-compliance, if not recovered in our rates, could adversely affect our operations and financial results, especially if emission and/or discharge limits are tightened, more extensive permitting requirements are imposed, additional substances become regulated and the number and types of assets we operate increase. We cannot estimate our compliance costs or any possible fines or penalties with certainty, or the degree to which such costs might be recovered in our rates, due to our inability to predict the requirements and timing of implementation of environmental laws or regulations. For example, the EPA has issued in the recent past various proposed regulations regarding air emissions, such as the revision of the primary and secondary ground-level ozone National Ambient Air

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Quality Standards ("NAAQS"). If these regulations become finalized and survive legal challenges, the cost to us to comply could adversely affect our operations and our financial results.

Climate Change and Related Legislation and Regulatory Initiatives Could Affect Demand for

Electricity or Availability of Resources, and Could Result in Increased Compliance Costs

The Company emits GHG (including carbon dioxide) through the operation of its power plants. Federal legislation had been introduced in both houses of Congress to regulate GHG emissions and numerous states have adopted programs to stabilize or reduce GHG emissions. Additionally, the EPA is proceeding with regulation of GHG under the CAA. Under EPA regulations finalized in May 2010, formerly known as the "Tailoring Rule", the EPA can impose GHG best achievable control technology requirements for sources, including power plants already required to implement prevention of significant deterioration under the CAA for certain other pollutants.

In addition, in October 2015, the EPA published a final rule establishing new source performance standards ("NSPS") limiting CO2 emissions from new, modified and reconstructed electric generating units. In October 2015, the EPA also published a rule establishing guidelines for states to regulate CO2 emissions from existing power plants, as well as a proposed "federal plan" to address CO2 emissions from affected units in those states that do not submit an approvable compliance plan. The standards for existing plants are known as the Clean Power Plan ("CPP"), under which rule interim emissions performance rates must be achieved beginning in 2022 and final emissions performance rates by 2030. Legal challenges to the CPP have been filed by groups of states and industry members. On February 9, 2016, the U.S. Supreme Court issued a decision to stay the rule until legal issues are resolved. Further, the U.S. signed on to 21st Conference of Parties Paris Agreement signed on December 12, 2015, and indications are that the U.S. plans on relying heavily on the CPP to meet its early commitments. The potential impact of this Agreement and GHG rules (if and when 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 possible to predict how any pending, proposed or future GHG legislation by Congress, the states or multi-state regions or any GHG regulations adopted by the EPA or state environmental agencies will impact our business. However, any legislation or regulation of GHG emissions or any future related litigation could result in increased compliance costs or additional operating restrictions or increased or reduced demand for our services, could require us to purchase rights to emit GHG, and could have a material adverse effect on our business, financial condition, reputation or results of operations.

Adverse Regulatory Decisions or Changes in Applicable Regulations Could Have a Material Adverse Effect on Our

Business or Result in Significant Additional Costs

Our business is subject to extensive federal, state and local laws and regulations. FERC regulates the Company’s wholesale operations, provision of transmission services and compliance with federally mandated reliability standards. Additional regulatory authorities have jurisdiction over some of our operations and construction projects including the EPA, the DOE, the PUCT, the NMPRC and various local regulatory districts (including the cities of El Paso and Las Cruces).

We must periodically apply for licenses and permits from these various regulatory authorities and abide by their respective orders. Should the Company be unsuccessful in obtaining necessary licenses or permits or should these regulatory authorities initiate any investigations or enforcement actions or impose penalties or disallowances on us, our business could be adversely affected. Existing regulations may be revised or reinterpreted and new laws and regulations may be adopted or become applicable to the Company or the Company’s facilities in a manner that may have a detrimental effect on our business or result in significant additional costs because of our obligation to comply with those requirements.

Security Breaches, Criminal Activity, Terrorist Attacks and Other Disruptions to Our Infrastructure Could Interfere With Our Operations, Could Expose Us or Our Customers or Employees to a Risk of Loss, and Could Expose Us to Liability, Regulatory Penalties, Reputational Damage and Other Harm to Our Business

We rely upon our infrastructure to manage or support a variety of business processes and activities, including the generation, transmission and distribution of electricity, supply chain functions, and the invoicing and collection of payments from our customers. We also use information technology systems for internal accounting purposes and to comply with financial reporting, legal and tax requirements. Our information technology networks and infrastructure may be vulnerable to damage, disruptions or shutdowns due to attacks by hackers, breaches due to employee error or malfeasance, system failures, computer viruses, natural disasters, a physical attack on our facilities, or other catastrophic events. The occurrence of any of these events could impact the reliability of our generation, transmission and distribution systems and energy marketing and trading functions; could expose us or our customers or employees to a risk of loss or misuse of confidential information; and could result in legal claims or proceedings, liability or

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regulatory penalties against us, damage our reputation or otherwise harm our business. In addition, we may be required to incur significant costs to prevent or respond to damage caused by these disruptions or security breaches in the future.

Additionally, we cannot predict the impact that any future information technology or terrorist attack may have on the energy industry in general. The effects of such attacks against us or others in the energy industry could increase the cost of regulatory compliance, increase the cost of insurance coverage or result in a decline in the U.S. economy which could negatively affect our results of operations and financial condition. Ongoing and future governmental efforts to regulate cybersecurity in the energy industry could lead to increased regulatory compliance costs.

The Effects of Technological Advancement, Energy Conservation Measures and Distributed Generation Could Adversely Affect Our Operations and Financial Results

New technologies may emerge that could be superior to, or may not be compatible with, some of our existing technologies, and may require us to make significant expenditures to remain competitive. Our future success will depend, in part, on our ability to anticipate and adapt to technological changes in a cost-effective manner and to offer, on a timely basis, services that meet customer demands and evolving industry standards.

Additionally, the electric utility industry is undergoing other technological advances such as the expanded cost effective utilization of energy efficiency measures and distributed generation including solar rooftop projects. Customers’ increased use of energy efficiency measures and distributed generation could result in lower demand. Reduced demand due to energy efficiency measures and the use of distributed generation, to the extent not substantially offset through ratemaking mechanisms, could have a material adverse impact on our financial condition, results of operations and cash flows.

Provisions in Our Corporate Documents, Franchise Agreements and State Law Could Delay or Prevent a Change in Control of the Company, Even if That Change Would Be Beneficial to Our Shareholders

Our Articles of Incorporation and Bylaws contain provisions that may make acquiring control of the Company difficult and could preclude our shareholders from receiving a change of control premium, including:


•	provisions relating to the classification, nomination and removal of our directors;


•	provisions regulating the ability of our shareholders to bring matters for action at annual meetings of our shareholders;


•	provisions limiting the ability to call special meetings of the shareholders to the Chairman of the Board, our Chief Executive Officer, our Secretary, the majority of the Board of Directors or the holders of at least 25% of the outstanding shares of our capital stock entitled to vote at such meeting;


•	provisions restricting our ability to engage in a wide range of “Business Combination” transactions with an “Interested Shareholder” (generally, any person who owns 15% or more of our outstanding voting power) or any affiliate or associate of an Interested Shareholder, unless specific conditions are met; and


•	the authorization given to our Board of Directors or any duly designated committee to issue and set the terms of preferred stock.

Our El Paso franchise agreement states that any assignment of the franchise agreement, including a deemed assignment as a result of a change in control of the Company, requires the consent of the City of El Paso.

In addition, Texas law prohibits us from engaging in a business combination with any shareholder for three years from the date that person became an affiliated shareholder by beneficially owning 20% or more of our outstanding common stock, in the absence of certain board of director or shareholder approvals.

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Item 1B.	Unresolved Staff Comments

None.


Item 2.	Properties

The principal properties of the Company are described in Item 1, "Business," and such descriptions are incorporated herein by reference. Transmission lines are located either on company-owned land, private rights-of-ways, easements, or on streets or highways by public consent.

The Company owns an executive and administrative office building and the Eastside Operations Center ( the "EOC"), which opened in early 2015, in El Paso County. 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 has several other leases for office and parking facilities that expire within the next five years.


Item 3.	Legal Proceedings

The Company is involved in various legal, environmental, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies regarding matters arising in the ordinary course of business. In many of these matters, the Company has excess casualty liability insurance that covers the various claims, actions and complaints. The Company regularly analyzes current information and, as necessary, makes provisions in its financial statements for probable liabilities for the eventual disposition of these matters. While the outcome of these matters cannot be predicted with certainty, based upon a review of the matters and applicable insurance coverage, the Company believes that none of these matters will have a material adverse effect on the financial position, results of operations or cash flows of the Company.

See Item 1, Business - Environmental Matters and Regulation, and Part II, Item 8, Financial Statements and Supplementary Data, Note C, Note L and Note K of Notes to Financial Statements" for discussion of the effects of government legislation and regulation on the Company as well as certain pending legal proceedings.


Item 4.	Mine Safety Disclosures

Not Applicable.

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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:



	Sales Price
	High		Low		Close		Dividends
					(End of period)
2014
First Quarter	$	37.16	$	33.44	$	35.73	$	0.265
Second Quarter	40.33		35.21		40.21		0.280
Third Quarter	40.43		35.39		36.55		0.280
Fourth Quarter	42.17		35.34		40.06		0.280
2015
First Quarter	$	41.32	$	35.43	$	38.64	$	0.280
Second Quarter	39.26		33.77		34.66		0.295
Third Quarter	38.32		33.90		36.82		0.295
Fourth Quarter	40.35		35.32		38.50		0.295

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, 2010 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.



	12/31/2010	12/31/2011	12/31/2012	12/31/2013	12/31/2014	12/31/2015
EE	100	128	121	137	161	160
EEI Index	100	120	123	138	178	172
NYSE Composite	100	94	106	131	136	127

As of January 31, 2016, there were 2,437 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 $47.1 million in cash dividends during the twelve months ended December 31, 2015. On January 28, 2016, the Board of Directors declared a quarterly cash dividend of $0.295 per share payable on March 31, 2016 to shareholders of record on March 15, 2016. The Board of Directors plans to review the Company's dividend policy annually in the second quarter of each year. Generally, we are targeting a payout ratio of approximately 45% to 55%. Declaration and payment of dividends is subject to compliance with certain financial tests under Texas law. Since 1999, the Company has also returned cash to 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, 2015 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)	Average Price Paid per Share (Including Commissions)		Total Number of Shares Purchased as Part of a Publicly Announced Program	Maximum Number of Shares that May Yet Be Purchased Under the Plans or Programs
October 1 to October 31, 2015	—	$	—	—	393,816
November 1 to November 30, 2015	—	—		—	393,816
December 1 to December 31, 2015	12,313	37.42		—	393,816

_____________________

(a) Represents shares of common stock delivered to us as payment of withholding taxes due upon the vesting of

restricted stock held by our employees, not considered part of the 2011 Plan.

For Equity Compensation Plan Information see Part III, Item 12 – "Security Ownership of Certain Beneficial Owners and Management."

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Item 6. Selected Financial Data

As of and for the following periods (in thousands except for share and per share data):



	Years Ended December 31,
	2015		2014		2013		2012		2011
Operating revenues	$	849,869	$	917,525	$	890,362	$	852,881	$	918,013
Operating income	146,191		$	151,163	$	165,635	$	168,658	$	190,803
Net income	$	81,918	$	91,428	$	88,583	$	90,846	$	103,539
Basic earnings per share:
Net income	$	2.03	$	2.27	$	2.20	$	2.27	$	2.49
Weighted average number of shares outstanding	40,274,986		40,190,991		40,114,594		39,974,022		41,349,883
Diluted earnings per share:
Net income	$	2.03	$	2.27	$	2.20	$	2.26	$	2.48
Weighted average number of shares and dilutive
potential shares outstanding	40,308,562		40,211,717		40,126,647		40,055,581		41,587,059
Dividends declared per share of common stock	$	1.165	$	1.105	$	1.045	$	0.97	$	0.66
Cash additions to utility property, plant and equipment	$	281,458	$	277,078	$	237,411	$	202,387	$	178,041
Total assets	$	3,233,852	$	3,059,301	$	2,786,288	$	2,669,050	$	2,396,851
Long-term debt, net of current portion	$	1,134,284	$	1,134,179	$	999,620	$	999,535	$	816,497
Common stock equity	$	1,016,538	$	984,254	$	943,833	$	824,999	$	760,251

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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"). Part II, Item 8, Financial Statements and Supplementary Data, Note A of Notes to Financial Statements contains a summary of our significant accounting policies, many of which require the use of estimates and assumptions. We believe that of our significant accounting policies, the following are noteworthy because they are based on estimates and assumptions that require complex, subjective assumptions by management, which can materially impact reported results. The Company evaluates its estimates on an on-going basis, including those related to depreciation, unbilled revenue, income taxes, fuel costs, pension and other post-retirement obligations and ARO. Changes in these estimates or assumptions, or actual results that are different, could materially impact our financial condition and results of operation.

Regulatory Accounting

We apply accounting standards that recognize the economic effects of rate regulation in our Texas, New Mexico and FERC jurisdictions. As a result, we record certain costs or obligations as either assets or liabilities on our balance sheet and amortize them in subsequent periods as they are reflected in regulated rates. The deferral of costs as regulatory assets is appropriate only when the future recovery of such costs is probable. In assessing probability, we consider such factors as specific regulatory orders, regulatory precedent and the current regulatory environment. As of December 31, 2015, we had recorded regulatory assets currently subject to recovery in future rates of approximately $115.1 million and regulatory liabilities of approximately $24.3 million as discussed in greater detail in Part II, Item 8, Financial Statements and Supplementary Data, Note D of Notes to Financial Statements. Included in regulatory assets are regulatory tax assets of approximately $69.4 million primarily related to the regulatory treatment of the equity portion of allowance for funds used during construction ("AFUDC") and state deferred income taxes.

In the event we determine that we can no longer apply the Financial Accounting Standards Board (the "FASB") guidance for regulated operations to all or a portion of our operations or to the individual regulatory assets recorded, based on regulatory action, we could be required to record a charge against income in the amount of the unamortized balance of the related regulatory assets. Such an action could materially reduce our total assets, specifically our total deferred charges and other assets, and shareholders' equity.

Collection of Fuel Expense

In general, by law and regulation, our actual fuel and purchased power expenses are recovered from our customers. In times of rising fuel prices, we experience a lag in recovery of higher fuel costs. These costs are subject to reconciliation by the PUCT on a periodic basis every one to three years. The NMPRC, in its discretion, may order that a prudence review be conducted to assure that fuel and purchased power costs recovered from customers are prudently incurred. Prior to the completion of a reconciliation proceeding or audit, we record fuel transactions such that fuel revenues, including fuel costs recovered through base rates in New Mexico, equal fuel expense. In the event that a disallowance of fuel cost recovery occurs during a reconciliation proceeding or an audit, the amounts recorded for fuel and purchased power expenses could differ from the amounts we are allowed to collect from our customers, and we could incur a loss to the extent of the disallowance.

The Company’s Texas fuel and purchased power costs through March 31, 2013 were reconciled in PUCT Docket No. 41852. As of December 31, 2015, Texas jurisdictional fuel and purchased power costs subject to a future Texas fuel reconciliation are approximately $413.8 million. The Company is required to file an application in 2016 for fuel reconciliation of the Company's fuel expenses in its Texas jurisdiction for the period through March 31, 2016. The NMPRC approved the continuation of its use of the Fuel and Purchase Power Cost Adjustment Clause without modification and the Company’s application requesting reconciliation of fuel and purchased power costs through December 2012 in Case No. 13-00380-UT. New Mexico jurisdictional costs subject to prudence review are for costs from January 2013 through December 31, 2015 and are approximately $194.4 million.

The Company recovers fuel and purchased power costs from the RGEC pursuant to an ongoing contract with a two-year notice to terminate provision. The contract includes a fuel adjustment clause designed to recover all eligible fuel and purchased power costs allocable to the RGEC and is updated on an annual basis. This update is reviewed and approved by the RGEC annually in February following the prior calendar year. As of December 31, 2015, the RGEC fuel costs subject to review are approximately $1.4 million.

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Decommissioning Costs and Estimated Asset Retirement Obligation

Pursuant to the ANPP Participation Agreement, the rules and regulations of the Nuclear Regulatory Commission and federal law, we must fund our share of the estimated costs to decommission Palo Verde Units 1, 2, 3 and associated common areas. The determination of the estimated liability is based on site-specific estimates, which are updated every three years and involve numerous judgments and assumptions, including estimates of future decommissioning costs at current price levels, escalation rates and discount rates. The Palo Verde ARO is approximately $72.8 million and represents approximately 89% of our total ARO balance of $81.6 million at December 31, 2015. A 10% increase in the estimates of future Palo Verde decommissioning costs at current price levels would have increased the ARO liability by $6.0 million at December 31, 2015.

We are required to fund estimated nuclear decommissioning costs over the life of the generating facilities through the use of external trust funds pursuant to rules of the Nuclear Regulatory Commission and PUCT and the ANPP Participation Agreement. Historically, we have been permitted to collect in rates in Texas and New Mexico the funding requirements for our nuclear decommissioning trusts, except for a portion of Palo Verde Unit 3, which is deregulated in the New Mexico jurisdiction. While we attempt to seek amounts in rates to meet decommissioning obligations, we are not able to conclude given the evidence available to us now that it is probable these costs will continue to be collected over the period until decommissioning begins in 2044. We are ultimately responsible for these costs and our future actions combined with future decisions from regulators will determine how successful we are in this effort.

The funding amounts are based on assumptions about future investment returns and future decommissioning cost escalations. If the rates of return earned by the trusts fail to meet expectations or if estimated costs to decommission the nuclear plant increase, we could be required to increase our funding to the nuclear decommissioning trusts.

Our decommissioning trust funds consist of equity securities and fixed income instruments and are carried at fair value. We face interest rate risk on the fixed income instruments, which consist primarily of municipal, federal and corporate bonds and which were valued at $113.3 million as of December 31, 2015. A hypothetical 10% increase in interest rates would have reduced the fair values of these funds by $1.2 million at December 31, 2015. Our decommissioning trust funds also include marketable equity securities of approximately $117.5 million at December 31, 2015. A hypothetical 20% decrease in equity prices would have reduced the fair values of these funds by $23.5 million at December 31, 2015. Declines in market prices could require that additional amounts be contributed to our nuclear decommissioning trusts to maintain minimum funding requirements.

We do not anticipate expending monies held in the nuclear decommissioning trusts before 2044 or a later period when decommissioning of Palo Verde begins.

Future Pension and Other Post-retirement Obligations

We maintain a qualified noncontributory defined benefit pension plan, which covers substantially all of our employees, and two non-funded nonqualified supplement plans that provide benefits in excess of amounts permitted under the provisions of the tax law for certain participants in the qualified plan. We also sponsor a plan that provides other post-retirement benefits, such as health and life insurance benefits to retired employees. Our net obligations under these various benefit plans at December 31, 2015 totaled $147.2 million and are recorded as liabilities on our balance sheet. The net periodic benefit costs for these plans totaled $11.0 million for the twelve months ended December 31, 2015.

Our pension and other post-retirement benefit liabilities and the related net periodic benefit costs are calculated on the basis of a number of actuarial assumptions regarding discount rates, expected return on plan assets, rate of compensation increase, life expectancy of retirees and health care cost inflation. For 2015, the discount rates used to measure our year end liabilities are based on a segmented spot rate yield curve that matches projected future payments with the appropriate interest rate applicable to the timing of the projected future benefit payments. As of December 31, 2015, the corresponding weighted-average discount rates range from 3.99% to 4.59% depending upon the benefit plan.

Our overall expected long-term rate of return on assets for the pension trust fund is 7.0% effective January 1, 2016, which is both a pre-tax and after-tax rate as pension funds are generally not subject to income tax. Our overall expected long-term rate of return on assets for the other post-retirement benefits trust, on an after-tax basis, is 4.875% effective January 1, 2016. Both expected long-term rates of return are based on the after-tax weighted average of the expected returns on investments. The expected returns on investments in the pension trust and the other post-retirement benefits trust are based upon the target asset allocations for the two trusts.

Our accrued post-retirement benefit liability and the service and interest components of the related net periodic benefit costs are calculated using an actuarial assumption regarding health care cost inflation. For measurement purposes, a 7.0% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2016. Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plan.

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The estimated rate of compensation increase used in our Retirement Plans is 4.5% and is based on recent trends for all non-union employees and the amounts we are contractually obligated for union employees.

In fiscal 2016, we expect to change the method used to estimate the service and interest components of net periodic benefit cost for pension and other postretirement benefits. This change compared to the previous method will result in a decrease in the service and interest components in future periods. Historically, we estimated service and interest costs utilizing a single weighted-average discount rate derived from the yield curve used to measure the benefit obligation at the beginning of the period. For fiscal 2016, we have elected to utilize a full yield curve approach to estimate these components by applying the specific spot rates along the yield curve used in the determination of the benefit obligation to the relevant projected cash flows. We believe the new approach provides a more precise measurement of service and interest costs by aligning the timing of the plan’s liability cash flows to the corresponding spot rates on the yield curve. We will account for this change as a change in accounting estimate and accordingly will account for this prospectively. The change in estimate is anticipated to decrease the service and interest components of net period benefit cost for pension and other post-retirement benefits by $2.9 million and $0.9 million, respectively, starting in 2016.

The following table reflects the sensitivities that a change in certain actuarial assumptions would have had on the December 31, 2015 reported pension liability and our 2015 reported pension expense (in thousands):



	Increase (Decrease)
Actuarial Assumption	Impact on Pension Liability			Impact on Pension Expense
Discount rate:
Increase 1%	$	(40,115	)	$	(3,779	)
Decrease 1%	49,216			4,574
Expected long-term rate of return on plan assets:
Increase 1%	N/A			2,633
Decrease 1%	N/A			(2,633		)
Compensation rate:
Increase 1%	6,188			1,470
Decrease 1%	(5,640		)	(1,316		)

The following chart reflects the sensitivities that a change in certain actuarial assumptions would have had on the December 31, 2015 other postretirement benefit obligations and our 2015 reported other postretirement benefit expense (in thousands):



	Increase (Decrease)
Actuarial Assumption	Impact on Other Post-retirement Benefit Obligation			Impact on Other Post-retirement Benefit Expense			Impact on Other Post-retirement Service and Interest Cost
Discount rate:
Increase 1%	$	(11,754	)	$	(1,750	)	$	(423	)
Decrease 1%	14,528			2,208			526
Healthcare cost trend rate:
Increase 1%	13,006			3,041			1,571
Decrease 1%	(11,718		)	(2,396		)	(1,211		)
Expected long-term rate of return on plan assets:
Increase 1%	N/A			(398		)	N/A
Decrease 1%	N/A			398			N/A

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Tax Accruals

We use the asset and liability method of accounting for income taxes. Under this method, we recognize deferred tax assets and liabilities for the future tax consequences attributable to temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities. The application of income tax law and regulations is complex and we make judgments regarding income tax exposures. Changes in these judgments, due to changes in law, regulation, interpretation or audit adjustments can materially affect amounts we recognize in our financial statements.

When appropriate, we record a valuation allowance against deferred tax assets to reflect that these tax assets may not be realized. In assessing the likelihood of the realization of deferred tax assets, management considers the estimated amount and character of future taxable income. Significant changes in these judgments and estimates could have a material impact on the results of operations and financial position of the Company. There were no valuation allowances for deferred tax assets at December 31, 2015.

We recognize tax benefits that are more likely than not to be sustained upon examination by tax authorities. The amount recognized is measured as the largest amount of benefit that is greater than 50 percent likely to be realized upon settlement. The unrecognized tax benefits that do not meet the recognition and measurement standards are $3.6 million at December 31, 2015.

Overview

The following is an overview of our results of operations for the years ended December 31, 2015, 2014 and 2013. Net income and basic earnings per share for the years ended December 31, 2015, 2014 and 2013 are shown below:



	Years Ended December 31,
	2015		2014		2013
Net income (in thousands)	$	81,918	$	91,428	$	88,583
Basic earnings per share	2.03		2.27		2.20

Regulatory Lag

Our results of operations for the year ended December 31, 2015 compared to 2014 and 2013 have been negatively impacted as a result of the completion and the placement in service of MPS Units 1 and 2 (including common plant, transmission lines and substation) and the EOC in the first quarter of 2015, without a corresponding increase in revenues. This trend will continue until new and higher rates become effective. The primary impact from these assets being placed in service includes a reduction in amounts capitalized for allowance for funds used during construction ("AFUDC"), and increases in depreciation, operation and maintenance expense, property taxes and interest cost.

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The following table and accompanying explanations show the primary factors affecting the after-tax change in income between the calendar years ended 2015 and 2014, 2014 and 2013, and 2013 and 2012 (in thousands):



	2015				2014				2013
Prior year December 31 net income	$	91,428			$	88,583			$	90,846
Change in (net of tax):
Increased (decreased) non-base revenue, net of energy expense	(5,370		)	(a)	3,779			(b)	2,345			(c)
Increased (decreased) allowance for funds used during construction	(4,953		)	(d)	6,157			(e)	895
Increased interest on long-term debt (net of capitalized interest)	(4,516		)	(f)	(390		)		(2,611		)	(g)
Increased depreciation and amortization	(4,214		)	(h)	(2,415		)	(i)	(696		)
(Increased) decreased administrative and general expense	(1,653		)	(j)	1,536			(k)	(2,011		)	(l)
Increased taxes other than income taxes	(641		)		(3,252		)	(m)	(198		)
Decreased (increased) operation and maintenance at fossil-fuel generating plants	(294		)		(1,792		)	(n)	751
Increased (decreased) retail non-fuel base revenues	9,290			(o)	(3,533		)	(p)	(2,459		)	(q)
Increased (decrease) investment and interest income	3,084			(r)	5,309			(s)	1,382			(s)
Decreased (increased) Palo Verde operations and maintenance expense	1,030				(1,635		)	(t)	964
Other	(1,273		)		(919		)		(625		)
Current year December 31 net income	$	81,918			$	91,428			$	88,583

______________________

Footnotes reflect pre-tax amounts

(a)

Non-base revenues, net of energy expenses decreased due to: (i) a decrease of $5.3 million in deregulated Palo Verde Unit 3 revenues; (ii) the recognition in 2014 of Palo Verde performance rewards of $2.2 million associated with the 2009 to 2012 performance periods, net of disallowed fuel and purchased power costs related to the resolution for the Texas fuel reconciliation proceeding designated as PUCT Docket No. 41852; and (iii) a decrease of $0.7 million in energy efficiency bonuses awarded. These decreases were partially offset by an increase of $1.7 million in transmission wheeling revenues.

(b)

Non-base revenues, net of energy expenses increased due to: (i) recognition of $2.2 million, in Palo Verde performance rewards associated with the 2009 to 2012 performance periods, net of disallowed fuel and purchased power costs related to the resolution of the Texas fuel reconciliation proceeding designated as PUCT Docket No. 41852; (ii) a $2.0 million, Texas Energy Efficiency bonus awarded in the fourth quarter of 2014; and (iii) an increase of $3.6 million in deregulated Palo Verde Unit 3 revenues. The increase was partially offset by a decrease of $3.3 million in transmission wheeling revenues.


(c)	Non-base revenues, net of energy expenses increased due to an increase of $1.6 million in deregulated Palo Verde Unit 3 revenues and an increase of $0.5 million in off-system sales retained margins.


(d)	AFUDC decreased primarily due to lower balances of construction work in process primarily due to MPS Units 1 and 2, and the EOC being placed in service during the first quarter of 2015 and a reduction in the AFUDC rate.


(e)	AFUDC increased, primarily due to higher balances of construction work in progress subject to AFUDC, primarily reflecting construction work in progress on MPS and the EOC.


(f)	Interest on long-term debt increased, primarily due to interest on $150 million of 5.00% Senior Notes issued in December 2014.


(g)	Interest on long-term debt increased, 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.


(h)	Depreciation and amortization increased due to increased depreciable plant balances including MPS Units 1 and 2 and the EOC which began commercial operation in the first quarter of 2015, partially offset by a change in the estimated useful life of certain large intangible software systems.


(i)	Depreciation and amortization increased due to increased depreciable plant balances including Rio Grande Unit 9, which began commercial operation in the second quarter of 2013.

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(j)	Administrative and general expenses increased, primarily due to (i) increased employee incentive compensation and (ii) increased pension and benefits costs due to changes in actuarial assumptions used to calculate expenses for the post- retirement employee benefit plan. These increases were partially offset by decreased outside services in the current period compared to the same period in 2014.


(k)	Administrative and general expense decreased, primarily due to decreased employee pensions and benefits reflecting changes in actuarial assumptions used to calculate expenses for our employee pension and post-retirement benefit plans and plan modifications.


(l)	Administrative and general expenses increased, 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 Four Corners.


(m)	Taxes other than income taxes increased, primarily due to higher property tax values and assessment rates. Additionally, in the first quarter of 2014, the Arizona tax district in which Palo Verde operates adjusted its 2013 property tax rate resulting in an additional charge of $1.3 million.


(n)	Operations and maintenance at our fossil fuel generating plants increased, primarily due to maintenance at the Four Corners and Newman power stations in 2014 with a reduced level of maintenance expense in 2013, and increased payroll expense.

(o)

Retail non-fuel base revenues increased, primarily due to (i) increased revenues of $11.9 million from our residential customers due to hotter weather in the third quarter of 2015 contributing to a 4.9% increase in kWh sales; (ii) increased revenues of $2.0 million from small commercial and industrial customers due to a 1.1% increase in kWh sales resulting from hotter weather and a 1.6% increase in the average number of customers; and (iii) a $1.2 million increase from large commercial and industrial customers. These increases were partially offset by an $0.8 million decrease from sales to public authorities due to a military installation moving a portion of their load to an interruptible rate.

(p)

Retail non-fuel base revenues decreased, primarily due to (i) a $3.0 million reduction in revenues from sales to public authorities reflecting increased use of an interruptible rate at a military installation in our service territory as well as other energy saving programs at military installations; (ii) a $2.3 million decrease in sales to residential customers primarily due to milder weather; and (iii) a $1.0 million decrease in sales to large commercial and industrial customers.


(q)	Retail non-fuel base revenues decreased, primarily due to a decrease in 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 sales to public authorities.


(r)	Investment and interest income increased, primarily due to further diversification and re-balancing our Palo Verde decommissioning trust fund equity portfolio.


(s)	Investment and interest income increased, primarily due to increased gains on the sales of equity investments in our Palo Verde decommissioning trust funds.


(t)	Palo Verde operations and maintenance expense increased primarily due to increased payroll including incentive compensation.

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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 2015, 2014 and 2013.

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,
	2015		2014		2013
Residential	44	%	42	%	43	%
Commercial and industrial, small	33		34		33
Commercial and industrial, large	7		7		7
Sales to public authorities	16		17		17
Total retail non-fuel base revenues	100	%	100	%	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 77% of our non-fuel base revenues. While this customer base is more stable, it is also more sensitive to changes in weather conditions. The current rate structures in New Mexico and Texas reflect higher base rates during the peak summer season of May through October and lower base rates during November through April for our residential and small commercial and industrial customers. As a result, our business is seasonal, with higher kWh sales and revenues during the summer cooling season. The following table sets forth the percentage of our retail non-fuel base revenues derived during each quarter for the periods presented:



	Years Ended December 31,
	2015		2014		2013
January 1 to March 31	18	%	19	%	20	%
April 1 to June 30	26		27		27
July 1 to September 30	35		33		33
October 1 to December 31	21		21		20
Total	100	%	100	%	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 2015, 2014 and 2013.



	2015	2014	2013	10-year Average
Cooling degree days	2,839	2,671	2,695	2,696
Heating degree days	2,095	1,900	2,426	2,174

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Customer growth is a key driver in the growth of retail sales. The average number of retail customers grew 1.4% and 1.3% in 2015 and 2014, respectively. See the tables presented on pages 34 and 35 which provide detail on the average number of retail customers and the related revenues and kWh sales.

Retail non-fuel base revenues. Retail non-fuel base revenues increased $14.3 million, or 2.6%, for the twelve months ended December 31, 2015 when compared to the twelve months ended December 31, 2014. This increase includes an $11.9 million increase in revenues from residential customers and a $2.0 million increase in revenues from small commercial and industrial customers reflecting hotter summer weather and increases of 1.3% and 1.6%, respectively, in the average number of residential customers and small commercial and industrial customers. KWh sales to public authorities increased 1.5% while revenue declined by $0.8 million primarily due to a military installation moving a portion of their load to an interruptible rate. Retail non-fuel revenues from large commercial and industrial customers increased $1.2 million due to an interruptible rate adjustment for a large customer. Cooling degree days increased 6.3% in 2015, when compared to the same period last year, and were 5.3% over the 10-year average. Heating degree days increased 10.3% for 2015, compared to 2014, and were 3.6% below the 10-year average.

Retail non-fuel base revenues decreased by $5.4 million, or 1.0%, for the twelve months ended December 31, 2014 when compared to the twelve months ended December 31, 2013. The decrease reflects a $3.0 million decrease from sales to public authorities, primarily due to an increased use of an interruptible rate by a military installation customer, as well as other energy savings from energy conservation and efficiency programs and use of solar distributed generation at military installations. The decrease in retail non-fuel base revenues also resulted from a decline in sales to residential customers of $2.3 million and reflects milder weather in 2014, primarily in the first quarter. The milder weather also suppressed sales to small commercial and industrial customers, and to a lesser extent public authority customers. Heating degree days decreased 21.7% when compared to 2013, and were 12.9% below the 10-year average. Cooling degree days were relatively consistent with both 2013 and the 10-year average. KWh sales to residential customers decreased 1.4% while the average number of residential customers served increased 1.3%. Retail non-fuel base revenues from sales to small commercial and industrial customers increased slightly, when compared to 2013, due to a 2.0% increase in the average number of customers served partially offset by milder weather. KWh sales to, and retail non-fuel base revenues from, large commercial and industrial customers decreased 2.8% and 2.5%, respectively, as several customers terminated operations.

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 an approved formula at least four months after our last revision, except in the month of December. In addition, if we materially over-recover fuel costs, we must seek to refund the over-recovery, and if we materially under-recover fuel costs, we may seek a surcharge to recover those costs. Fuel over and under recoveries are defined as material when they exceed 4% of the previous twelve months' fuel costs.

We over-recovered fuel costs by $13.3 million in the twelve months ended December 31, 2015. We under-recovered fuel costs by $3.1 million and $10.8 million in the twelve months ended December 31, 2014 and 2013, respectively. In May 2014, we implemented a 6.9% increase in our fixed fuel factor in Texas, which was based upon a formula that reflects increases in prices for natural gas. On April 15, 2015, the Company filed a request, which was assigned PUCT Docket No. 44633, to reduce its fixed fuel factor by approximately 24% to reflect an expected reduction in fuel expense. The over-recovered balance was below the materiality threshold. The reduction in the fixed fuel factor was effective on an interim basis May 1, 2015 and approved by the PUCT on May 20, 2015. In July 2014, the PUCT approved a settlement in the Texas fuel reconciliation proceeding designated as PUCT Docket No. 41852 and financial implications of the settlement were recorded in the second quarter of 2014 increasing fuel revenues by $2.2 million. In September 2014 and March 2015, $7.9 million and $5.8 million, respectively, were credited to customers through the applicable fuel adjustment clauses as the result of a reimbursement from the DOE related to spent nuclear fuel storage. At December 31, 2015, we had a net fuel over-recovery balance of $4.0 million, including an over-recovery balance $0.1 million in Texas, $3.8 million in New Mexico and $0.1 million in the FERC jurisdiction.

Off-system sales. Off-system sales are wholesale sales into markets outside our service territory. Off-system sales are primarily made in off-peak periods when we have competitive generation capacity available after meeting our regulated service obligations. We have shared 100% of margins on non-arbitrage sales (as defined by the settlement) and 50% of margins on arbitrage sales with our Texas customers since April 1, 2014. For the period from April 1, 2014 through June 30, 2015, our total share of margins assignable to the Texas retail jurisdiction, on arbitrage and non-arbitrage off-system sales, may not exceed 10% of the total margins assignable to the Texas retail jurisdiction on all off-system sales. Prior to April 1, 2014, we shared 90% of off-system sales margins with our Texas customers, and we retained 10% of off-system sales margins. We are currently sharing 90% of off-system sales margins with our New Mexico customers, and 25% of our off-system sales margins with our sales for resale customer under the terms of their contract.

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Typically, we realize a significant portion of our off-system sales margins in the first quarter of each calendar year when our native load is lower than at other times of the year, allowing for the sale in the wholesale market of relatively larger amounts of off-system energy generated from lower cost generating resources. Palo Verde's availability is an important factor in realizing these off-system sales margins.

The table below shows MWhs, sales revenue, fuel cost, total margins, and retained margins made on off-system sales for the twelve months ended December 31, 2015, 2014 and 2013 (in thousands except for MWhs).



	Years Ended December 31,
	2015		2014		2013
MWh sales	2,500,947		2,609,769		2,472,622
Sales revenue	$	64,816	$	97,980	$	82,806
Fuel cost	$	52,406	$	74,716	$	68,241
Total margins	$	12,410	$	23,264	$	14,565
Retained margins	$	1,362	$	2,147	$	1,549

Off-system sales revenues decreased $33.2 million, or 33.8%, and the related retained margins decreased $0.8 million, or 36.6%, for the twelve months ended December 31, 2015 when compared to 2014 as a result of lower average market prices for power and a 4.2% decrease in MWh sales. Off-system sales revenues increased $15.2 million, or 18.3%, and the related retained margins increased $0.6 million, or 38.6%, for the twelve months ended December 31, 2014 when compared to 2013 as a result of higher average market prices for power and a 5.5% increase in MWh sales.

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Comparisons of kWh sales and operating revenues are shown below:



						Increase (Decrease)
Years Ended December 31:	2015			2014		Amount			Percent
kWh sales (in thousands):
Retail:
Residential	2,771,138			2,640,535		130,603			4.9	%
Commercial and industrial, small	2,384,514			2,357,846		26,668			1.1
Commercial and industrial, large	1,062,662			1,064,475		(1,813		)	(0.2	)
Sales to public authorities	1,585,568			1,562,784		22,784			1.5
Total retail sales	7,803,882			7,625,640		178,242			2.3
Wholesale:
Sales for resale	63,347			61,729		1,618			2.6
Off-system sales	2,500,947			2,609,769		(108,822		)	(4.2	)
Total wholesale sales	2,564,294			2,671,498		(107,204		)	(4.0	)
Total kWh sales	10,368,176			10,297,138		71,038			0.7
Operating revenues (in thousands):
Non-fuel base revenues:
Retail:
Residential	$	246,265		$	234,371	$	11,894		5.1	%
Commercial and industrial, small	187,436			185,388		2,048			1.1
Commercial and industrial, large	40,411			39,239		1,172			3.0
Sales to public authorities	91,244			92,066		(822		)	(0.9	)
Total retail non-fuel base revenues	565,356			551,064		14,292			2.6
Wholesale:
Sales for resale	2,455			2,277		178			7.8
Total non-fuel base revenues	567,811			553,341		14,470			2.6
Fuel revenues:
Recovered from customers during the period	127,765			161,052		(33,287		)	(20.7	)
Under (over) collection of fuel (1)	(13,342		)	3,110		(16,452		)	-
New Mexico fuel in base rates	72,129			71,614		515			0.7
Total fuel revenues (2)	186,552			235,776		(49,224		)	(20.9	)
Off-system sales:
Fuel cost	52,406			74,716		(22,310		)	(29.9	)
Shared margins	11,048			21,117		(10,069		)	(47.7	)
Retained margins	1,362			2,147		(785		)	(36.6	)
Total off-system sales	64,816			97,980		(33,164		)	(33.8	)

Other (3) (4)	30,690			30,428		262			0.9
Total operating revenues	$	849,869		$	917,525	$	(67,656	)	(7.4	)
Average number of retail customers (5):
Residential	356,969			352,277		4,692			1.3	%
Commercial and industrial, small	40,250			39,600		650			1.6
Commercial and industrial, large	49			49		—			-
Sales to public authorities	5,250			5,088		162			3.2
Total	402,518			397,014		5,504			1.4

___________________________


(1)	Includes the portion of DOE refunds related to spent fuel storage of $5.8 million and $7.9 million in 2015 and 2014, respectively, that were credited to customers through the applicable fuel adjustment clauses. 2014 includes $2.2 million related to Palo Verde performance rewards, net.


(2)	Includes deregulated Palo Verde Unit 3 revenues for the New Mexico jurisdiction of $9.7 million and $15.0 million in 2015 and 2014, respectively.


(3)	Includes an Energy Efficiency Bonus of $1.3 million and $2.0 million in 2015 and 2014, respectively.


(4)	Represents revenues with no related kWh sales.


(5)	The number of retail customers presented is based on the number of service locations.

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					Increase (Decrease)
Years Ended December 31:	2014		2013		Amount			Percent
kWh sales (in thousands):
Retail:
Residential	2,640,535		2,679,262		(38,727		)	(1.4	)%
Commercial and industrial, small	2,357,846		2,349,148		8,698			0.4
Commercial and industrial, large	1,064,475		1,095,379		(30,904		)	(2.8	)
Sales to public authorities	1,562,784		1,622,607		(59,823		)	(3.7	)
Total retail sales	7,625,640		7,746,396		(120,756		)	(1.6	)
Wholesale:
Sales for resale	61,729		61,232		497			0.8
Off-system sales	2,609,769		2,472,622		137,147			5.5
Total wholesale sales	2,671,498		2,533,854		137,644			5.4
Total kWh sales	10,297,138		10,280,250		16,888			0.2
Operating revenues (in thousands):
Non-fuel base revenues:
Retail:
Residential	$	234,371	$	236,651	$	(2,280	)	(1.0	)%
Commercial and industrial, small	185,388		184,568		820			0.4
Commercial and industrial, large	39,239		40,235		(996		)	(2.5	)
Sales to public authorities	92,066		95,044		(2,978		)	(3.1	)
Total retail non-fuel base revenues	551,064		556,498		(5,434		)	(1.0	)
Wholesale:
Sales for resale	2,277		2,172		105			4.8
Total non-fuel base revenues	553,341		558,670		(5,329		)	(1.0	)
Fuel revenues:
Recovered from customers during the period	161,052		133,481		27,571			20.7
Under collection of fuel (1)	3,110		10,849		(7,739		)	(71.3	)
New Mexico fuel in base rates	71,614		73,295		(1,681		)	(2.3	)
Total fuel revenues (2)	235,776		217,625		18,151			8.3
Off-system sales:
Fuel cost	74,716		68,241		6,475			9.5
Shared margins	21,117		13,016		8,101			62.2
Retained margins	2,147		1,549		598			38.6
Total off-system sales	97,980		82,806		15,174			18.3

Other (3) (4)	30,428		31,261		(833		)	(2.7	)
Total operating revenues	$	917,525	$	890,362	$	27,163		3.1
Average number of retail customers (5):
Residential	352,277		347,891		4,386			1.3	%
Commercial and industrial, small	39,600		38,836		764			2.0
Commercial and industrial, large	49		50		(1		)	(2.0	)
Sales to public authorities	5,088		4,997		91			1.8
Total	397,014		391,774		5,240			1.3

_______________________


(1)	2014 includes a DOE refund related to spent fuel storage of $7.9 million offset in part by $2.2 million related to Palo Verde performance rewards, net.


(2)	Includes deregulated Palo Verde Unit 3 revenues for the New Mexico jurisdiction of $15.0 million and $11.4 million in 2014 and 2013, respectively.


(3)	Includes an Energy Efficiency Bonus of $2.0 million and $0.5 million in 2014 and 2013, respectively.


(4)	Represents revenues with no related kWh sales.


(5)	The number of retail customers presented is based on the number of service locations.

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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 31% of our available net generating capacity and approximately 54% of our Company-generated energy for the twelve months ended December 31, 2015. Fluctuations in the price of natural gas, which is also the primary factor influencing the price of purchased power, have had a significant impact on our cost of energy.

Energy expenses decreased $73.9 million, or 23.4%, for the twelve months ended December 31, 2015 compared to 2014, primarily due to (i) decreased natural gas costs of $62.5 million due to a 32.0% decrease in the average price of natural gas, (ii) decreased total purchased power of $11.3 million due to a 18.7% decrease in the average price of total purchased power, and (iii) decreased nuclear fuel expense of $1.2 million due to a 7.2% decrease in the cost of nuclear fuel consumed. The decrease in energy expense was partially offset by (i) a $2.1 million reduction in the 2015 DOE refund compared to 2014, and (ii) an increase in coal costs of $1.0 million due to a 10.3% increase in the MWhs generated with coal.

Energy expenses increased $26.7 million, or 9.2%, for the twelve months ended December 31, 2014 compared to 2013, primarily due to (i) increased natural gas costs of $32.7 million due to a 17.1% increase in the average costs of natural gas and a 2.4% increase in MWhs generated with natural gas, and (ii) increased total purchased power of $2.4 million due to a 17.5% increase in the average price of total purchased power partially offset by a 10.2% decrease in MWhs purchased. Photovoltaic purchased power costs per MWh decreased for the twelve months ended December 31, 2014, when compared to the same period in 2013 primarily due to the lower priced purchases from Macho Springs solar photovoltaic project which began commercial operation in May 2014. The increase in energy expense was partially offset by a decrease in nuclear fuel expense related to an $8.5 million settlement with the DOE for reimbursement of spent fuel storage and management costs recorded in 2014.

The table below details the sources and costs of energy for 2015, 2014 and 2013.



	2015						2014
Fuel Type	Cost			MWh	Cost per MWh		Cost			MWh	Cost per MWh
	(in thousands)						(in thousands)
Natural Gas	$	134,361		3,790,659	$	35.45	$	196,833		3,774,209	$	52.15
Coal	13,913			657,744	21.15		12,883			596,252	21.61
Nuclear	40,126		(a)	5,136,686	9.06		41,289		(a)	5,106,668	9.76
Total	188,400			9,585,089	20.32		251,005			9,477,129	27.39
Purchase Power:
Photovoltaic	22,495			277,241	81.14		19,575			227,979	85.86
Other	31,050			1,113,705	27.88		45,229			1,162,511	39.80
Total purchased power	53,545			1,390,946	38.50		64,804			1,390,490	47.35
Total energy	$	241,945		10,976,035	22.63		$	315,809		10,867,619	29.94


	2013
Fuel Type	Cost			MWh	Cost per MWh
	(in thousands)
Natural Gas	$	164,139		3,686,823	$	44.52
Coal	13,680			635,717	21.52
Nuclear	48,949			4,966,233	9.86
Total	226,768			9,288,773	24.41
Purchase Power:
Photovoltaic	13,863			120,926	114.64
Other	48,500			1,427,004	33.99
Total purchased power	62,363			1,547,930	40.29
Total energy	$	289,131		10,836,703	26.68

_____________________

(a) Costs includes a DOE refund related to spent fuel storage of $6.4 million and $8.5 million recorded in the first quarter of 2015 and in the third quarter of 2014, respectively. Cost per MWh excludes this settlement.

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Other operations expense

Other operations expense increased $4.1 million, or 1.7%, in 2015 compared to 2014 primarily due to (i) a $4.0 million increase in other operations payroll costs including a $1.5 million increase in employee incentive compensation; (ii) increased pension and benefits costs due to changes in actuarial assumptions used to calculate expenses for the post-retirement benefit plan; (iii) a $1.7 million increase in operations expenses at our fossil-fuel generating plants primarily due to expenses at our MPS with no comparable expenses during 2014; and (iv) a $1.5 million increase in transmission and distribution expenses related to wheeling expense and system support and improvements. These increases were partially offset by (i) a $1.9 million decrease in outside services expenses and (ii) a $1.4 million decrease in Palo Verde operations expense.

Other operations expense increased $1.7 million, or 0.7%, in 2014 compared to 2013 primarily due to (i) a $5.6 million increase in other operations payroll costs including a $2.7 million increase in employee incentive compensation; (ii) a $1.5 million increase in customer care expenses including an increase in uncollectible customer accounts; and (iii) a $1.5 million increase in Palo Verde operations expense. These increases were partially offset by $5.5 million decrease in employee pensions and benefits primarily due to changes in actuarial assumptions used to calculate expenses for our employee pension and post-retirement benefit plans and plan modifications.

Maintenance expense

Maintenance expense decreased $0.4 million, or 0.6%, in 2015 compared to 2014 primarily due to a decrease in the level of maintenance at our Rio Grande and Four Corners generating plants partially offset by maintenance at our MPS with no comparable expenses during 2014. Maintenance expense increased $4.6 million, or 7.5%, in 2014 compared to 2013 due to an increase in maintenance expense at Four Corners and Newman generating plants and increased payroll expense.

Depreciation and amortization expense

Depreciation and amortization expense increased $6.5 million, or 7.8%, in 2015 compared to 2014, primarily due to the increases in depreciable plant balances including MPS Units 1 and 2 and the EOC, which were placed in service during the first quarter of 2015, partially offset by an increase in the estimated useful lives of certain large intangible software systems effective July 2015 in the amount of $1.8 million. Depreciation and amortization expense increased $3.7 million, or 4.7%, in 2014 compared to 2013, due to increases in depreciable plant balances primarily in our transmission and distribution plant and our local generating plant, including Rio Grande Unit 9 which began commercial operation on May 13, 2013.

Taxes other than income taxes

Taxes other than income taxes increased $1.0 million, or 1.6%, in 2015 compared to 2014, primarily due to (i) higher property tax values and assessment rates, and (ii) additional payroll taxes. Taxes other than income taxes increased $5.0 million, or 8.7%, in 2014 compared to 2013, primarily due to higher property tax values and assessment rates and increases in revenue related taxes. Additionally, in the first quarter of 2014, the Arizona tax district in which Palo Verde operates adjusted its 2013 property tax rate, resulting in an additional charge of $1.3 million.

Other income (deductions)

Other income (deductions) decreased $2.3 million, or 8.1%, in 2015 compared to 2014, primarily as a result of: (i) decreased allowance for equity funds used during construction ("AEFUDC") resulting from lower average balances of construction work in progress and a reduction in the AEFUDC rate; and (ii) higher gains recognized on the sales of land in 2014 compared to 2015. This decrease was partially offset by increased investment and interest income due to further diversification and re-balancing of our Palo Verde decommissioning trust find equity portfolio.

Other income (deductions) increased $13.9 million in 2014 compared to 2013, primarily as a result of: (i) increased investment and interest income due to increased net realized gains on equity investments in our decommissioning trusts; (ii) increased AEFUDC due to higher balances of construction work in progress including MPS and the EOC; and (iii) an increase in miscellaneous other income due to a gain recognized on sale of assets in 2014 with a reduced level of activity in 2013.

Interest charges (credits)

Interest charges (credits) increased by $8.4 million, or 18.0%, in 2015 compared to 2014 primarily due to interest expense on the $150 million aggregate principal amount of 5.00% Senior Notes due 2044 issued in December 2014 and decreased allowance for borrowed funds used during construction ("ABFUDC") as a result of lower balances of construction work in progress and a reduction in the ABFUDC rate.

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Interest charges (credits) decreased by $0.9 million, or 1.9%, in 2014 compared to 2013 primarily due to increased ABFUDC as a result of higher balances of construction work in progress in 2014 partially offset by an increase in interest on short-term borrowings for working capital purposes and interest expense on the $150 million of 5.00% Senior Notes due 2044 issued in December 2014.

Income tax expense

Income tax expense decreased by $6.2 million, or 15.1%, in 2015 compared to 2014 primarily due to (i) a decrease in the pre-tax income, and (ii) a decrease in state income taxes. These decreases were partially offset by a decrease in AEFUDC. Income tax expense decreased by $2.6 million, or 5.9%, in 2014 compared to 2013 primarily due to (i) an increase in the AEFUDC, (ii) an increase in capital gains on equity investments in our decommissioning trusts which are taxed at a lower rate, and (iii) an increase in tax credits earned. These decreases were partially offset by an increase in state income taxes.

New accounting standards

In May 2014, the FASB issued new guidance (Accounting Standards Update ("ASU") 2014-09, Revenue from Contracts with Customers (Topic 606)) to provide a framework that replaces the existing revenue recognition guidance. ASU 2014-09 is the result of a joint effort by the FASB and the International Accounting Standards Board intended to clarify the principles for recognizing revenue and to develop a common revenue standard for U.S. Generally Accepted Accounting Principles ("GAAP") and International Financial Reporting Standards. ASU 2014-09 provides that an entity should recognize the amount of revenue to which it expects to be entitled for the transfer of promised goods or services to customers. ASU 2014-09 was originally intended to be effective for annual periods and interim periods within that reporting period beginning after December 15, 2016, for public business entities. In August 2015, the FASB issued ASU 2015-14 to defer the effective date of ASU 2014-09 for all entities by one year. Public business entities will apply the guidance in ASU 2014-09 to annual reporting periods beginning after December 15, 2017 and interim periods within that reporting period. Early adoption of ASU 2014-09 is permitted after December 15, 2016. We have not selected a transition method and we are currently assessing the future impact of this ASU.

In April 2015, the FASB issued ASU 2015-03, Interest - Imputation of Interest (Topic 715) to simplify the presentation of debt issuance costs. ASU 2015-03 requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by this ASU. ASU 2015-03 is effective for financial statements issued for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. In August 2015, the FASB issued ASU 2015-15, Interest - Imputation of Interest (Subtopic 835-30), to provide further clarification to ASU 2015-03 as it relates to the presentation and subsequent measurement of debt issuance costs associated with line of credit arrangements. We do not expect ASU 2015-03 and ASU 2015-15 to materially impact the Company's results of operations and cash flows.

In May 2015, the FASB issued ASU 2015-07, Fair Value Measurement (Topic 820) to eliminate the requirement to categorize investments in the fair value hierarchy if the fair value is measured at net asset value ("NAV") per share (or its equivalent) using the practical expedient in the FASB’s fair value measurement guidance. Reporting entities must still provide sufficient information to enable users to reconcile total investments in the fair value hierarchy and total investments measured at fair value in the financial statements. Additionally, the scope of current disclosure requirements for investments eligible to be measured at NAV will be limited to investments to which the practical expedient is applied. This ASU is effective in fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. The ASU requires retrospective application. Early adoption is permitted. This guidance requires a revision of the fair value disclosures but will not impact our financial statements.

In November 2015, the FASB issued new guidance (ASU 2015-17, Balance Sheet Classification of Deferred Taxes) to simplify the presentation of deferred income taxes. ASU 2015-17 requires that deferred tax liabilities and assets be classified as noncurrent in a classified statement of financial position. ASU 2015-17 can be applied prospectively or retrospectively and is effective for financial statements issued for annual periods beginning after December 15, 2016 and interim periods within those annual periods and early adoption is permitted. We are currently assessing the future impact of this ASU.

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tax asset related to available-for-sale securities in combination with the entity's other deferred tax assets. The standard includes a requirement that businesses must report changes in the fair value of their own liabilities in other comprehensive income instead of earnings, and this is the only provision of the update for which the FASB is permitting early adoption. The remaining provisions of this ASU become effective for public companies for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. We are currently assessing the future impact of this ASU.

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, 2015, our capital structure, including common stock, long-term debt, current maturities of long-term debt, and short-term borrowings under the RCF, consisted of 44.3% common stock equity and 55.7% debt. At December 31, 2015, we had on hand $8.1 million in cash and cash equivalents. Based on current projections, we believe that we will have adequate liquidity through the issuance of long-term debt, our current cash balances, cash from operations, and available borrowings under the Revolving Credit Facility (“RCF”) to meet all of our anticipated cash requirements for the next twelve months.

Our principal liquidity requirements in the near-term are expected to consist of capital expenditures to expand and support electric service obligations, expenditures for nuclear fuel inventory, interest payments on our indebtedness, cash dividend payments, operating expenses including fuel costs, maintenance costs and taxes.

Capital Requirements. During the twelve months ended December 31, 2015, our capital requirements primarily consisted of expenditures for the construction and purchase of electric utility plant, cash dividend payments and purchases of nuclear fuel. Projected utility construction expenditures are to add new generation, expand and update our transmission and distribution systems, and make capital improvements and replacements at Palo Verde and other generating facilities. MPS Units 1 and 2, the first two (of four) natural gas-fired 88 MW simple-cycle aeroderivative combustion turbines, were completed and placed in service during the first quarter of 2015. The total cost for these two units and the related common facilities and transmission systems, including AFUDC, was approximately $228.7 million. Units 3 and 4 are projected to be completed in 2016. In 2015 we incurred approximately $120.4 million in cost for MPS, including AFUDC. Estimated cash construction expenditures for MPS in 2016 are approximately $39 million and estimated construction expenditures for all capital projects for 2016 are approximately $231 million. See Part I, Item 1, "Business - Construction Program." Cash capital expenditures for new electric plant were $281.5 million in the twelve months ended December 31, 2015 and $277.1 million in the twelve months ended December 31, 2014. Capital requirements for purchases of nuclear fuel were $42.0 million for the twelve months ended December 31, 2015 and $37.9 million for the twelve months ended December 31, 2014.

On December 30, 2015, we paid a quarterly cash dividend of $0.295 per share or $11.9 million to shareholders of record on December 15, 2015. We paid a total of $47.1 million in cash dividends during the twelve months ended December 31, 2015. On January 28, 2016, our Board of Directors declared a quarterly cash dividend of $0.295 per share payable on March 31, 2016 to shareholders of record at the close of business on March 15, 2016 which will require cash of $11.9 million. We expect to continue paying quarterly dividends during 2016 and we expect to review the dividend policy in the second quarter of 2016. At the current payout rate, we would expect to pay total cash dividends of approximately $47.6 million during 2016. In addition, while we do not currently anticipate repurchasing shares of our common stock in 2016, we may repurchase shares of our common stock in the future. Under our repurchase program, purchases can be made at open market prices or in private transactions, and repurchased shares are available for issuance under employee benefit and stock incentive plans, or may be retired. Beginning in 2015 shares of our common stock issued for employee benefit and stock incentive plans have been issued from the shares repurchased and held in treasury stock. During 2015, 108,085 shares were awarded out of treasury stock. No shares of our common stock were repurchased in 2015, 2014 or 2013. As of December 31, 2015, 393,816 shares remain eligible for repurchase under the repurchase program.

We will continue to maintain a prudent level of liquidity and monitor market conditions for debt and equity securities. We primarily utilize the distribution of dividends to maintain a balanced capital structure and supplement this effort with share repurchases when appropriate. Our liquidity needs can fluctuate quickly based on fuel prices and other factors and we are continuing to make investments in new electric plant and other assets in order to reliably serve our customers. In light of these factors, we expect it will be a number of years before we achieve a dividend payout equivalent to industry average.

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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, income tax payments are expected to be minimal in 2016.

We continually evaluate our funding requirements related to our retirement plans, other post-retirement benefit plans, and decommissioning trust funds. We contributed $10.9 million to our retirement plans during both the twelve months ended December 31, 2015 and 2014. We contributed $0.5 million to our other post-retirement benefit plans during the twelve months ended December 31, 2015 and we did not make any contributions to our other post-retirement benefit plans during the twelve months ended December 31, 2014. We contributed $4.5 million to our decommissioning trust funds in both 2015 and 2014. We are in compliance with the funding requirements of the federal government for our benefit plans. In addition, with respect to our nuclear plant decommissioning trust, we are in compliance with the funding requirements of the federal law and the ANPP Participation Agreement. We will continue to review our funding for these plans in order to meet our future obligations.

In 2010, the Company and RGRT, a Texas grantor trust through which we finance our portion of fuel for Palo Verde, entered into a note purchase agreement with various institutional purchasers. Under the terms of the agreement, RGRT sold to the purchasers $110 million aggregate principal amount of senior notes. In August 2015, $15.0 million of these senior notes matured and were paid with borrowings from the RCF.

Capital Resources. Cash provided by operations, $246.7 million in 2015 and $243.3 million in 2014, is a significant source for funding capital requirements. Cash from operations has been impacted by the timing of the recovery of fuel costs through fuel recovery mechanisms in Texas and New Mexico and our sales for resale customer. We recover actual fuel costs from customers through fuel adjustment mechanisms in Texas, New Mexico, and from our sales for resale customer. We record deferred fuel revenues for the under-recovery or over-recovery of fuel costs until they can be recovered from or refunded to customers. In Texas, fuel costs are recovered through a fixed fuel factor. We can seek to revise our fixed fuel factor at least four months after our last revision except in the month of December based upon our approved formula which allows us to adjust fuel rates to reflect changes in costs of natural gas. We are required to request to refund fuel costs in any month when the over-recovery balance exceeds a threshold material amount and we expect fuel costs to continue to be materially over-recovered. We are permitted to seek to surcharge fuel under-recoveries in any month the balance exceeds a threshold material amount that we expect fuel cost recovery to continue to be materially under-recovered. Fuel over and under-recoveries are considered material when they exceed 4% of the previous twelve months' fuel costs. On May 1, 2015, we reduced our fixed fuel factor charged to our Texas retail customers by approximately 24% to reflect reduced fuel expense.

2015 earnings were adversely impacted by the regulatory lag resulting from placing into service during the first quarter, the first two generating units at MPS together with the related transmission lines and substation as well as the EOC. We incurred approximately $269.3 million in construction costs for these facilities. With the introduction of these facilities into service, we have begun to incur increased expenses related to depreciation, operations and maintenance, property taxes, and interest cost. Furthermore, we have ceased recognizing AFUDC on these facilities. We have filed for an increase in base rates for our New Mexico and Texas service territory on May 11, 2015 and August 10, 2015, respectively; and we expect new rates to become effective in the second quarter of 2016 in both jurisdictions. The Company also expects 2016 earnings to be adversely impacted by the regulatory lag resulting from the commercialization of MPS Units 3 and 4 which are expected to be placed in service during the second and fourth quarters of 2016, respectively. Base rate increases to seek recovery of these costs are expected to be filed in the first quarter of 2017 for both jurisdictions.

During the twelve months ended December 31, 2015, net fuel recoveries resulted in increased cash from operations when compared to 2014. During the twelve months ended December 31, 2015 the Company had a fuel over-recovery of $13.3 million compared to an under-recovery of fuel costs of $3.1 million during the twelve months ended December 31, 2014. At December 31, 2015, we had a net fuel over-recovery balance of $4.0 million, including an over-recovery balance of $0.1 million in Texas, $3.8 million in New Mexico and $0.1 million in the FERC jurisdiction.

In December 2014, we issued $150 million aggregate principal amount of 5.00% Senior Notes due December 1, 2044. The gross proceeds from the issuance of the senior notes were $149.5 million, net of a $0.5 million discount before commissions and expenses and the effective interest rate was 5.10%. The net proceeds from the sale of these senior notes were used to fund construction expenditures and to repay the outstanding balance of our RCF used for working capital and general corporate purposes.

We maintain the RCF for working capital and general corporate purposes and the financing of nuclear fuel through the RGRT. The RGRT is the trust through which we finance our portion of nuclear fuel for Palo Verde and is consolidated in our 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. In August 2015, $15 million Series A

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3.67% Senior Notes of the RGRT matured and were paid utilizing the RCF. The total amount borrowed for nuclear fuel by the RGRT was $128.7 million at December 31, 2015, of which $33.7 million had been borrowed under the RCF and $95 million was borrowed through the issuance of senior notes. Borrowings by RGRT for nuclear fuel were $124.5 million at December 31, 2014, of which $14.5 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 the RGRT and charged to us as fuel is consumed and recovered from customers through fuel recovery charges. The outstanding balance for working capital or general corporate purposes was $108 million at December 31, 2015. No borrowings were outstanding December 31, 2014 for working capital and general corporate purposes. Total aggregate borrowings under the RCF at December 31, 2015 were $141.7 million with an additional $157.8 million available to borrow.

We believe we have adequate liquidity through our current cash balances, cash from operations, available borrowings under the RCF and potential access to capital markets to meet all of our anticipated cash requirements for the next twelve months. We received approval from the NMPRC on October 7, 2015 and from the FERC on October 19, 2015, to issue up to $310 million in new long-term debt and to guarantee the issuance of up to $65 million of new debt by the RGRT to finance future purchases of nuclear fuel and to refinance existing nuclear fuel debt obligations. We also received approval from the FERC to continue to utilize our existing RCF without change from the FERC’s previously approved authorization. The FERC authorization is effective from November 15, 2015 through November 15, 2017. The approvals granted in these cases supersede prior approvals. The authorizations to issue up to $310 million of long-term debt and to guarantee up to $65 million of new long-term debt by RGRT provides us with the flexibility to access the debt capital markets if conditions are favorable.

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Contractual Obligations. Our contractual obligations as of December 31, 2015 are as follows (in thousands):



	Payments due by period
	Total		2016		2017 and 2018		2019 and 2020		2021 and Beyond
Long-Term Debt (including interest):
Senior notes (1)	$	1,823,275	$	47,700	$	95,400	$	95,400	$	1,584,775
Pollution control bonds (2)	444,836		10,583		53,634		19,918		360,701
RGRT Senior notes (3)	110,810		4,503		56,771		49,536		—
Financing Obligations (including interest):
Revolving credit facility (4)	143,683		143,683		—		—		—
Purchase Obligations:
Power contracts	891		891		—		—		—
Fuel contracts:
Coal (5)	2,855		2,855		—		—		—
Gas (5)	348,962		52,959		63,833		62,009		170,161
Nuclear fuel (6)	106,332		25,590		28,312		19,875		32,555
Retirement Plans and Other Post-retirement benefits (7)	7,892		7,892		—		—		—
Nuclear decommissioning trust funds (8)	2,000		2,000		—		—		—
Operating leases (9)	10,358		900		1,186		1,089		7,183
Total	$	3,001,894	$	299,556	$	299,136	$	247,827	$	2,155,375

_____________________

(1)

We have four outstanding issuances of Senior Notes. In May 2005, we issued $400 million aggregate principal amount of 6% Senior Notes due May 15, 2035. In June 2008, we issued $150 million aggregate principal amount of 7.5% Senior Notes due March 15, 2038. In December 2012, we issued $150 million aggregate principal amount of 3.3% Senior Notes due December 15, 2022. In December 2014, we issued $150 million aggregate principal amount of 5.0% Senior Notes due December 1, 2044.


(2)	We have four series of pollution control bonds that are scheduled for remarketing and/or mandatory tender, one in 2017, two in 2040, and one in 2042.

(3)

In 2010, the Company and RGRT entered into a note purchase agreement for $110 million aggregate principal amount of senior notes consisting of: (a) $15 million aggregate principal amount of 3.67% RGRT Senior Notes, Series A, which matured and were repaid on August 15, 2015; (b) $50 million aggregate principal amount of 4.47% RGRT Senior Notes, Series B, due August 15, 2017; and (c) $45 million aggregate principal amount of 5.04% RGRT Senior Notes, Series C, due August 15, 2020.


(4)	This reflects obligations outstanding under the $300 million RCF. At December 31, 2015, $108.0 million was borrowed for working capital and general corporate purposes and $33.7 million was borrowed by RGRT for nuclear fuel. This balance includes interest based on actual interest rates at the end of 2015 and assumes this amount will be outstanding for the entire year of 2016.


(5)	Amount is based on the minimum volumes per the contract and market and/or contract price at the end of 2015. Gas obligation includes a gas storage contract and a gas transportation contract.


(6)	Some of the nuclear fuel contracts are based on a fixed price, adjusted for a market index. The index used here is the index at the end of 2015.

(7)

This obligation is based on our expected contributions and includes our minimum contractual funding requirements for the non-qualified retirement income plan and the other post-retirement benefits for 2016. We have no minimum cash contractual funding requirement related to our retirement income plan or other post-retirement benefits for 2016. However, we are subject to minimum funding requirements of ERISA. We also may decide to fund at higher levels and expect to contribute $7.9 million to our retirement plans in 2016, as disclosed in Part II, Item 8, Notes to Financial Statements, Note M. Minimum funding requirements for 2017 and beyond are not included due to the uncertainty of interest rates and the related return on assets.


(8)	This obligation is based on our expected contributions in 2016. We anticipate having no minimum funding obligation in either Texas or New Mexico jurisdiction once new rates become effective given that funding was not requested in either PUCT Docket No. 44941or NMPRC Case No. 15-00127-UT. The current funding levels of $0.3 million per month in

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Texas and $0.1 million per month in New Mexico are anticipated to continue until the new rates go into effect. However, funding requirements may change in the future and could require an increase in funding levels in both jurisdictions.


(9)	We lease land in El Paso adjacent to the Newman Power Station under a lease that expires in June 2033 with a renewal option of 25 years. We also have several other leases for office, parking facilities and equipment that expire within the next five years.

Off-Balance Sheet Arrangements

We have no off-balance sheet arrangements that have or are reasonably likely to have a current or future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources.

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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.

Equity Price Risk

Our decommissioning trust funds include marketable equity securities of approximately $117.5 million and $123.4 million at December 31, 2015 and 2014, respectively. A hypothetical 20% decrease in equity prices would have reduced the fair values of these funds by $23.5 million and $24.7 million based on their fair values at December 31, 2015 and 2014, respectively. Declines in market prices could require that additional amounts be contributed to our nuclear decommissioning trusts to maintain minimum funding requirements. We do not expect to expend monies held in trust before 2044 or a later period when decommissioning of Palo Verde begins.

Commodity Price Risk

We utilize contracts of various durations for the purchase of natural gas, 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, 2016, we had entered into forward sales and purchase contracts for energy as discussed in Part I, Item 1, "Business – Energy Sources – Purchased Power." These agreements are generally fixed-priced contracts that qualify for the "normal purchases and normal sales" exception provided in the FASB guidance for accounting for derivative instruments and hedging activities and are not recorded at their fair value in our financial statements. Because of the operation of the PUCT and the NMPRC rules and our fuel clauses, these contracts do not expose us to significant commodity price risk.

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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, 2015. In making this assessment, the Company’s management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission's 2013 Internal Control - Integrated Framework. Based on its assessment, management believes that, as of December 31, 2015, 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 47 of this report.

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Item 8.Financial Statements and Supplementary Data

INDEX TO FINANCIAL STATEMENTS



	Page

Report of Independent Registered Public Accounting Firm	47

Balance Sheets as of December 31, 2015 and 2014	48

Statements of Operations for the years ended December 31, 2015, 2014 and 2013	50

Statements of Comprehensive Operations for the years ended December 31, 2015, 2014 and 2013	51

Statements of Changes in Common Stock Equity for the years ended December 31, 2015, 2014 and 2013	52

Statements of Cash Flows for the years ended December 31, 2015, 2014 and 2013	53

Notes to Financial Statements	54

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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 (the Company) as of December 31, 2015 and 2014, 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, 2015. We also have audited El Paso Electric Company’s internal control over financial reporting as of December 31, 2015, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). El Paso Electric Company’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on these financial statements and an opinion on the Company’s internal control over financial reporting based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of El Paso Electric Company as of December 31, 2015 and 2014, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2015, 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, 2015, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

/s/ KPMG LLP

Kansas City, Missouri

February 29, 2016

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EL PASO ELECTRIC COMPANY

BALANCE SHEETS



ASSETS (In thousands)	December 31,
	2015			2014
Utility plant:
Electric plant in service	$	3,616,301		$	3,229,255
Less accumulated depreciation and amortization	(1,329,843		)	(1,266,672		)
Net plant in service	2,286,458			1,962,583
Construction work in progress	293,796			414,284
Nuclear fuel; includes fuel in process of $51,854 and $46,996, respectively	190,282			185,185
Less accumulated amortization	(75,031		)	(73,701		)
Net nuclear fuel	115,251			111,484
Net utility plant	2,695,505			2,488,351
Current assets:
Cash and cash equivalents	8,149			40,504
Accounts receivable, principally trade, net of allowance for doubtful accounts of $2,046 and $2,253, respectively	66,326			71,165
Accumulated deferred income taxes	21,621			13,957
Inventories, at cost	48,697			45,889
Under-collection of fuel revenues	—			10,253
Prepayments and other	9,872			12,213
Total current assets	154,665			193,981
Deferred charges and other assets:
Decommissioning trust funds	239,035			234,286
Regulatory assets	115,127			112,086
Other	29,520			30,597
Total deferred charges and other assets	383,682			376,969
Total assets	$	3,233,852		$	3,059,301

See accompanying notes to financial statements.

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EL PASO ELECTRIC COMPANY

BALANCE SHEETS (Continued)



CAPITALIZATION AND LIABILITIES (In thousands except for share data)	December 31,
	2015			2014
Capitalization:
Common stock, stated value $1 per share, 100,000,000 shares authorized, 65,709,819 and 65,725,246 shares issued, and 118,834 and 124,297 restricted shares, respectively	$	65,829		$	65,850
Capital in excess of stated value	320,073			318,515
Retained earnings	1,067,396			1,032,537
Accumulated other comprehensive loss, net of tax	(13,914		)	(8,001		)
	1,439,384			1,408,901
Treasury stock, 25,384,834 and 25,492,919 shares, respectively, at cost	(422,846		)	(424,647		)
Common stock equity	1,016,538			984,254
Long-term debt, net of current portion	1,134,284			1,134,179
Total capitalization	2,150,822			2,118,433
Current liabilities:
Current maturities of long-term debt	—			15,000
Short-term borrowings under the revolving credit facility	141,738			14,532
Accounts payable, principally trade	59,978			78,862
Taxes accrued	30,351			28,210
Interest accrued	12,649			12,758
Over-collection of fuel revenues	4,023			932
Other	28,325			24,715
Total current liabilities	277,064			175,009
Deferred credits and other liabilities:
Accumulated deferred income taxes	516,858			474,154
Accrued pension liability	90,527			94,272
Accrued post-retirement benefit liability	54,553			59,342
Asset retirement obligation	81,621			74,577
Regulatory liabilities	24,303			26,099
Other	38,104			37,415
Total deferred credits and other liabilities	805,966			765,859
Commitments and contingencies
Total capitalization and liabilities	$	3,233,852		$	3,059,301

See accompanying notes to financial statements.

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EL PASO ELECTRIC COMPANY

STATEMENTS OF OPERATIONS

(In thousands except for share data)



	Years Ended December 31,
	2015			2014			2013
Operating revenues	$	849,869		$	917,525		$	890,362
Energy expenses:
Fuel	188,400			251,005			226,768
Purchased and interchanged power	53,545			64,804			62,363
	241,945			315,809			289,131
Operating revenues net of energy expenses	607,924			601,716			601,231
Other operating expenses:
Other operations	242,950			238,832			237,155
Maintenance	65,223			65,629			61,068
Depreciation and amortization	89,824			83,342			79,626
Taxes other than income taxes	63,736			62,750			57,747
	461,733			450,553			435,596
Operating income	146,191			151,163			165,635
Other income (deductions):
Allowance for equity funds used during construction	10,639			14,662			10,008
Investment and interest income, net	17,508			13,633			7,033
Miscellaneous non-operating income	2,062			4,075			909
Miscellaneous non-operating deductions	(4,328		)	(4,199		)	(3,635		)
	25,881			28,171			14,315
Interest charges (credits):
Interest on long-term debt and revolving credit facility	65,851			59,028			58,635
Other interest	1,313			1,250			431
Capitalized interest	(4,968		)	(5,092		)	(5,299		)
Allowance for borrowed funds used during construction	(6,937		)	(8,368		)	(6,055		)
	55,259			46,818			47,712
Income before income taxes	116,813			132,516			132,238
Income tax expense	34,895			41,088			43,655
Net income	$	81,918		$	91,428		$	88,583

Basic earnings per share	$	2.03		$	2.27		$	2.20

Diluted earnings per share	$	2.03		$	2.27		$	2.20

Dividends declared per share of common stock	$	1.165		$	1.105		$	1.045
Weighted average number of shares outstanding	40,274,986			40,190,991			40,114,594
Weighted average number of shares and dilutive potential shares outstanding	40,308,562			40,211,717			40,126,647

See accompanying notes to financial statements.

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EL PASO ELECTRIC COMPANY

STATEMENTS OF COMPREHENSIVE OPERATIONS

(In thousands)



	Years Ended December 31,
	2015			2014			2013
Net income	$	81,918		$	91,428		$	88,583
Other comprehensive income (loss):
Unrecognized pension and post-retirement benefit costs:
Net gain (loss) arising during period	5,429			(54,328		)	82,964
Prior service benefit	824			34,200			97
Reclassification adjustments included in net income for amortization of:
Prior service benefit	(6,574		)	(7,659		)	(5,560		)
Net loss	8,622			6,182			10,472
Net unrealized gains/losses on marketable securities:
Net holding (losses) gains arising during period	(2,906		)	10,827			17,699
Reclassification adjustments for net gains included in net income	(11,114		)	(7,350		)	(553		)
Net losses on cash flow hedges:
Reclassification adjustment for interest expense included in net income	467			438			411
Total other comprehensive income (loss) before income taxes	(5,252		)	(17,690		)	105,530
Income tax benefit (expense) related to items of other comprehensive income (loss):
Unrecognized pension and post-retirement benefit costs	(3,286		)	8,051			(33,566		)
Net unrealized losses (gains) on marketable securities	2,828			(760		)	(3,100		)
Losses on cash flow hedges	(203		)	(214		)	(168		)
Total income tax benefit (expense)	(661		)	7,077			(36,834		)
Other comprehensive income (loss), net of tax	(5,913		)	(10,613		)	68,696
Comprehensive income	$	76,005		$	80,815		$	157,279

See accompanying notes to financial statements.

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EL PASO ELECTRIC COMPANY

STATEMENTS OF CHANGES IN COMMON STOCK EQUITY

(In thousands except for share data)



	Common Stock					Capital in Excess of Stated Value			Retained Earnings			Accumulated Other Comprehensive Income (Loss), Net of Tax			Treasury Stock					Common Stock Equity

	Shares		Amount												Shares		Amount
Balances at December 31, 2012	65,604,997		$	65,605		$	310,994		$	939,131		$	(66,084	)	25,492,919		$	(424,647	)	$	824,999
Restricted common stock grants and deferred compensation	96,279		96			2,702														2,798
Performance share awards vested	64,275		64			785														849
Stock awards withheld for taxes	(23,808	)	(23		)	(788		)												(811		)
Forfeited restricted common stock	(1,549	)	(1		)															(1		)
Deferred taxes on stock incentive plan						427														427
Stock options exercised	15,000		15			177														192
Compensation paid in shares	4,431		4			146														150
Net income									88,583											88,583
Other comprehensive income (loss)												68,696								68,696
Dividends declared									(42,049		)									(42,049		)
Balances at December 31, 2013	65,759,625		65,760			314,443			985,665			2,612			25,492,919		(424,647		)	943,833
Restricted common stock grants and deferred compensation	103,672		104			4,175														4,279
Stock awards withheld for taxes	(4,696	)	(5		)	(183		)												(188		)
Forfeited restricted common stock	(19,162	)	(19		)															(19		)
Deferred taxes on stock incentive plan						(302		)												(302		)
Compensation paid in shares	10,104		10			382														392
Net income									91,428											91,428
Other comprehensive income (loss)												(10,613		)						(10,613		)
Dividends declared									(44,556		)									(44,556		)
Balances at December 31, 2014	65,849,543		65,850			318,515			1,032,537			(8,001		)	25,492,919		(424,647		)	984,254
Restricted common stock grants and deferred compensation	6,356		6			2,266									(93,455	)	1,557			3,829
Stock awards withheld for taxes	(15,031	)	(15		)	(556		)												(571		)
Forfeited restricted common stock	(12,215	)	(12		)										871		(14		)	(26		)
Deferred taxes on stock incentive plan						(475		)												(475		)
Compensation paid in shares						323									(15,501	)	258			581
Net income									81,918											81,918
Other comprehensive income (loss)												(5,913		)						(5,913		)
Dividends declared									(47,059		)									(47,059		)
Balances at December 31, 2015	65,828,653		$	65,829		$	320,073		$	1,067,396		$	(13,914	)	25,384,834		$	(422,846	)	$	1,016,538

See accompanying notes to financial statements.

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EL PASO ELECTRIC COMPANY

STATEMENTS OF CASH FLOWS

(In thousands)



	Years Ended December 31,
	2015			2014			2013
Cash Flows From Operating Activities:
Net income	$	81,918		$	91,428		$	88,583
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization of electric plant in service	89,824			83,342			79,626
Amortization of nuclear fuel	43,099			43,864			42,537
Deferred income taxes, net	30,846			39,129			44,678
Allowance for equity funds used during construction	(10,639		)	(14,662		)	(10,008		)
Other amortization and accretion	17,707			18,380			16,556
Gain on sale of property, plant and equipment	(658		)	(2,092		)	(112		)
Net gains on sale of decommissioning trust funds	(11,114		)	(7,350		)	(553		)
Other operating activities	517			(93		)	(260		)
Change in:
Accounts receivable	4,839			(5,815		)	(2,450		)
Inventories	(2,859		)	(786		)	(3,673		)
Net over-collection (under-collection) of fuel revenues	13,344			(3,121		)	(10,843		)
Prepayments and other	(3,984		)	(2,750		)	(4,295		)
Accounts payable	(11,235		)	9,684			8,180
Taxes accrued	4,512			(2,209		)	(627		)
Other current liabilities	3,719			1,198			958
Deferred charges and credits	(3,165		)	(4,807		)	(822		)
Net cash provided by operating activities	246,671			243,340			247,475
Cash Flows From Investing Activities:
Cash additions to utility property, plant and equipment	(281,458		)	(277,078		)	(237,411		)
Cash additions to nuclear fuel	(41,966		)	(37,877		)	(30,535		)
Capitalized interest and AFUDC:
Utility property, plant and equipment	(17,576		)	(23,030		)	(16,063		)
Nuclear fuel	(4,968		)	(5,092		)	(5,299		)
Allowance for equity funds used during construction	10,639			14,662			10,008
Decommissioning trust funds:
Purchases, including funding of $4.5 million	(110,223		)	(117,675		)	(65,491		)
Sales and maturities	102,567			108,311			56,148
Proceeds from sale of property, plant and equipment	721			2,395			112
Other investing activities	(470		)	4,192			5,767
Net cash used for investing activities	(342,734		)	(331,192		)	(282,764		)
Cash Flows From Financing Activities:
Dividends paid	(47,059		)	(44,556		)	(42,049		)
Borrowings under the revolving credit facility:
Proceeds	344,398			231,399			44,883
Payments	(217,192		)	(231,219		)	(52,686		)
Payment on maturing RGRT senior notes	(15,000		)	—			—
Proceeds from issuance of senior notes	—			149,468			—
Other financing activities	(1,439		)	(2,328		)	(324		)
Net cash provided by (used for) financing activities	63,708			102,764			(50,176		)
Net increase (decrease) in cash and cash equivalents	(32,355		)	14,912			(85,465		)
Cash and cash equivalents at beginning of period	40,504			25,592			111,057
Cash and cash equivalents at end of period	$	8,149		$	40,504		$	25,592

See accompanying notes to financial statements.

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INDEX TO NOTES TO FINANCIAL STATEMENTS



	Page
Note A. Summary of Significant Accounting Policies	55

Note B. New Accounting Standards	58

Note C. Regulation	59

Note D. Regulatory Assets and Liabilities	63

Note E. Utility Plant, Palo Verde and Other Jointly-Owned Utility Plant	64

Note F. Accounting for Asset Retirement Obligations	68

Note G. Common Stock	69

Note H. Accumulated Other Comprehensive Income (Loss)	74

Note I. Long-Term Debt and Financing Obligations	76

Note J. Income Taxes	78

Note K. Commitments, Contingencies and Uncertainties	81

Note L. Litigation	85

Note M. Employee Benefits	86

Note N. Franchises and Significant Customers	98

Note O. Financial Instruments and Investments	99

Note P. Supplemental Statements of Cash Flow Disclosures	103

Note Q. Selected Quarterly Financial Data (Unaudited)	104

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EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

A. Summary of Significant Accounting Policies

General. El Paso Electric Company is a public utility engaged in the generation, transmission and distribution of electricity in an area of approximately 10,000 square miles in west Texas and southern New Mexico. The Company also serves a full requirements wholesale customer in Texas.

Basis of Presentation. The Company maintains its accounts in accordance with the Uniform System of Accounts prescribed by the Federal Energy Regulatory Commission (the "FERC").

Use of Estimates. The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The Company evaluates its estimates on an on-going basis, including those related to depreciation, unbilled revenue, income taxes, fuel costs, pension and other post-retirement obligations and asset retirement obligations ("ARO"). Actual results could differ from those estimates.

Application of the Financial Accounting Standards Board (the "FASB") Guidance for Regulated Operations. Regulated electric utilities typically prepare their financial statements in accordance with the FASB guidance for regulated operations. The FASB guidance for regulated operations requires the Company to include an allowance for equity and borrowed funds used during construction ("AEFUDC" and "ABFUDC") as a cost of construction of electric plant in service. AEFUDC is recognized as income and ABFUDC is shown as capitalized interest charges in the Company’s statement of operations. The FASB guidance for regulated operations also requires the Company to show certain recoverable costs as either assets or liabilities on a utility’s balance sheet if the regulator provides assurance that these costs will be charged to and collected from the utility’s customers (or has already permitted such cost recovery) or will be credited or refunded to the utility’s customers. The resulting regulatory assets or liabilities are amortized in subsequent periods based upon the respective amortization periods reflected in a utility’s regulated rates. See Part II, Item 8, Financial Statements and Supplementary Data, Note D. The Company applies the FASB guidance for regulated operations for all three of the jurisdictions in which it operates.

Comprehensive Income. Certain gains and losses that are not recognized currently in the statements of operations are reported as other comprehensive income in accordance with the FASB guidance for reporting comprehensive income.

Utility Plant. Utility plant is generally reported at cost. The cost of renewals and betterments are capitalized and the costs of repairs and minor replacements are charged to the appropriate operating expense accounts. Depreciation is provided on a straight-line basis over the estimated remaining lives of the assets (ranging in average from 5 to 48 years). The average composite depreciation rate utilized in 2015, 2014 and 2013 was 2.64%, 2.60%, and 2.61%, 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 Company currently reports gains and losses on dispositions of vehicles in earnings when realized. Beginning in 2016, the Company will adopt composite depreciation rates for vehicles. As such, the Company will charge the cost together with the cost of removal, less salvage on the disposition of vehicles to accumulated depreciation.

The cost of nuclear fuel is amortized to fuel expense on a units-of-production basis. The Company is also amortizing its share of costs associated with on-site spent fuel storage casks at Palo Verde over the burn period of the fuel that will necessitate the use of the storage casks. See Part II, Item 8, Financial Statements and Supplementary Data, Note E.

Impairment of Long-Lived Assets. Long-lived assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to estimated undiscounted future cash flows expected to be generated by the asset. If the carrying amount of an asset exceeds its estimated undiscounted future cash flows, an impairment charge is recognized for the amount by which the carrying amount of the asset exceeds the fair value of the asset.

AFUDC and Capitalized Interest. The Company capitalizes interest ("ABFUDC") and common equity ("AEFUDC") costs to construction work in progress and capitalizes interest to nuclear fuel in process in accordance with the FERC Uniform System of Accounts as provided for in the FASB guidance. AFUDC is a non-cash component of income and is calculated monthly and

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charged to all new eligible construction and capital improvement projects. AFUDC is compounded on a semi-annual basis. The average AFUDC rates used in 2015, 2014 and 2013 were 7.18%, 8.15% and 8.10%, respectively.

Asset Retirement Obligation. The FASB guidance sets forth accounting requirements for the recognition and measurement of liabilities associated with the retirement of tangible long-lived assets. An ARO associated with long-lived assets included within the scope of the FASB guidance is that for which a legal obligation exists under enacted laws, statutes, written or oral contracts, including obligations arising under the doctrine of promissory estoppel and legal obligations to perform an asset retirement activity even if the timing and/or settlement are conditioned on a future event that may or may not be within the control of an entity. See Part II, Item 8, Financial Statements and Supplementary Data, Note F. Under the FASB guidance, these liabilities are recognized as incurred if a reasonable estimate of fair value can be established and are capitalized as part of the cost of the related tangible long-lived assets. The Company records the increase in the ARO due to the passage of time as an operating expense (accretion expense).

Cash and Cash Equivalents. All temporary cash investments with an original maturity of three months or less are considered cash equivalents.

Investments. The Company’s marketable securities, included in decommissioning trust funds in the balance 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 Part II, Item 8, Financial Statements and Supplementary Data, Note O.

Derivative Accounting. Accounting for derivative instruments and hedging activities requires the recognition of derivatives as either assets or liabilities in the balance sheet with measurement of those instruments at fair value. Any changes in the fair value of these instruments are recorded in earnings or other comprehensive income. See Part II, Item 8, Financial Statements and Supplementary Data, Note O.

Inventories. Inventories, primarily parts, materials, supplies, fuel oil and natural gas are stated at average cost 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 are billed under base rates and a fuel adjustment clause which is adjusted monthly, as approved by the New Mexico Public Regulation Commission ("NMPRC"). The Company's FERC sales for resale customers are billed under formula base rates and fuel factors and a fuel adjustment clause which is adjusted monthly. The Company’s recovery of energy expenses is subject to periodic reconciliations of actual energy expenses incurred to actual fuel revenues collected. The difference between energy expenses incurred and fuel revenues charged to customers is reflected as over/under-collection of fuel revenues in the balance sheets. See Part II, Item 8, Financial Statements and Supplementary Data, Note C.

Revenues. Revenues related to the sale of electricity are generally recorded when service is provided or electricity is delivered to customers. The billing of electricity sales to retail customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. Unbilled revenues are recorded for estimated amounts of energy delivered in the period following the customers billing cycle to the end of the month. Unbilled revenues are estimated based on monthly generation volumes and by applying an average revenue/kWh to the number of estimated kWhs delivered but not billed. Accounts receivable included accrued unbilled revenues of $21.7 million and $21.2 million at December 31, 2015 and 2014, 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 2015, 2014 and 2013 are as follows (in thousands):

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	2015		2014		2013
Balance at beginning of year	$	2,253	$	2,261	$	2,906
Additions:
Charged to costs and expense	2,057		2,755		2,098
Recovery of previous write-offs	1,613		1,516		1,929
Uncollectible receivables written off	3,877		4,279		4,672
Balance at end of year	$	2,046	$	2,253	$	2,261

Income Taxes. The Company accounts for federal and state income taxes under the asset and liability method of accounting for income taxes. Deferred income taxes are recognized for the estimated future tax consequences of "temporary differences" by applying enacted statutory tax rates for each taxable jurisdiction applicable to future years to differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities. Certain temporary differences are accorded flow-through treatment by the Company's regulators and impact the Company's effective tax rate. The FASB guidance requires that rate-regulated companies record deferred income taxes for temporary differences accorded flow-through treatment at the direction of the regulatory commission. The resulting deferred tax assets and liabilities are recorded at the expected cash flow to be reflected in future rates. Because the Company's regulators have consistently permitted the recovery of tax effects previously flowed-through earnings, the Company has recorded regulatory liabilities and assets offsetting such deferred tax assets and liabilities. The effect on deferred tax assets and liabilities of a change in tax rate is recognized in income in the period that includes the enactment date. The Company recognizes tax assets and liabilities for uncertain tax positions in accordance with the recognition and measurement criteria of the FASB guidance for uncertainty in income taxes. See Part II, Item 8, Financial Statements and Supplementary Data, Note J.

Earnings per Share. The Company’s restricted stock awards are participating securities and earnings per share must be calculated using the two-class method in both the basic and diluted earnings per share calculations. For the basic earnings per share calculation, net income is allocated to the weighted average number of restricted stock awards and to the weighted average number of shares outstanding. The net income allocated to the weighted average number of shares outstanding is then divided by the weighted average number of shares outstanding to derive the basic earnings per share. For the diluted earnings per share, net income is allocated to the weighted average number of restricted stock awards and to the weighted average number of shares and dilutive potential shares outstanding. The Company’s dilutive potential shares outstanding amount is calculated using the treasury stock method for the unvested performance shares. Net income allocated to the weighted average number of shares and dilutive potential shares is then divided by the weighted average number of shares and dilutive potential shares outstanding to derive the diluted earnings per share. See Part II, Item 8, Financial Statements and Supplementary Data, Note G.

Stock-Based Compensation. The Company has a stock-based long-term incentive plan. The Company is required under the FASB guidance to measure the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award. Such costs are recognized over the period during which an employee is required to provide service in exchange for the award (the "requisite service period") which typically is the vesting period. Compensation cost is not recognized for anticipated forfeitures prior to vesting of equity instruments. See Part II, Item 8, Financial Statements and Supplementary Data, Note G.

Pension and Post-retirement Benefit Accounting. See Part II, Item 8, Financial Statements and Supplementary Data, Note M for a discussion of the Company’s accounting policies for its employee benefits.

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B. New Accounting Standards

In May 2014, the FASB issued new guidance (Accounting Standards Update ("ASU") 2014-09, Revenue from Contracts with Customers (Topic 606)) to provide a framework that replaces the existing revenue recognition guidance. ASU 2014-09 is the result of a joint effort by the FASB and the International Accounting Standards Board intended to clarify the principles for recognizing revenue and to develop a common revenue standard for U.S. Generally Accepted Accounting Principles ("GAAP") and International Financial Reporting Standards. ASU 2014-09 provides that an entity should recognize the amount of revenue to which it expects to be entitled for the transfer of promised goods or services to customers. ASU 2014-09 was originally intended to be effective for annual periods and interim periods within that reporting period beginning after December 15, 2016, for public business entities. In August 2015, the FASB issued ASU 2015-14 to defer the effective date of ASU 2014-09 for all entities by one year. Public business entities will apply the guidance in ASU 2014-09 to annual reporting periods beginning after December 15, 2017 and interim periods within that reporting period. Early adoption of ASU 2014-09 is permitted after December 15, 2016. The Company has not selected a transition method and is currently assessing the future impact of this ASU.

In April 2015, the FASB issued ASU 2015-03, Interest - Imputation of Interest (Topic 715) to simplify the presentation of debt issuance costs. ASU 2015-03 requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by this ASU. ASU 2015-03 is effective for financial statements issued for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. In August 2015, the FASB issued ASU 2015-15, Interest - Imputation of Interest (Subtopic 835-30), to provide further clarification to ASU 2015-03 as it relates to the presentation and subsequent measurement of debt issuance costs associated with line of credit arrangements. The Company does not expect ASU 2015-03 and ASU 2015-15 to materially impact the Company's results of operations and cash flows.

In November 2015, the FASB issued new guidance (ASU 2015-17, Balance Sheet Classification of Deferred Taxes) to simplify the presentation of deferred income taxes. ASU 2015-17 requires that deferred tax liabilities and assets be classified as noncurrent in a classified statement of financial position. ASU 2015-17 can be applied prospectively or retrospectively and is effective for financial statements issued for annual periods beginning after December 15, 2016 and interim periods within those annual periods and early adoption is permitted. The Company is currently assessing the future impact of this ASU.

In January 2016, the FASB issued ASU 2016-01, Financial Instruments-Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Liabilities to enhance the reporting model for financial instruments by addressing certain aspects of recognition, measurement, presentation, and disclosure. ASU 2016-01 requires entities to measure equity investments that do not result in consolidation and are not accounted for under the equity method at fair value and recognize any changes in fair value in net income unless the investments qualify for the new practicability exception. The guidance for classifying and measuring investments in debt securities and loans are not changed by this ASU, but requires entities to record changes in instrument-specific credit risk for financial liabilities measured under the fair value option in other comprehensive income. Financial assets and financial liabilities must be separately presented by measurement category and form of financial asset on the balance sheet or in the accompanying notes to the financial statements. ASU 2016-01 clarifies the need for a valuation allowance on a deferred tax asset related to available-for-sale securities in combination with the entity's other deferred tax assets. The standard includes a requirement that businesses must report changes in the fair value of their own liabilities in other comprehensive income instead of earnings, and this is the only provision of the update for which the FASB is permitting early adoption. The remaining provisions of this ASU become effective for public companies for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. The Company is currently assessing the future impact of this ASU.

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C. Regulation

General

Texas Regulatory Matters

2015 Texas Retail Rate Case Filing. On August 10, 2015, the Company filed with the City of El Paso, other municipalities incorporated in its Texas service territory, and the PUCT in Docket No. 44941, a request for an increase in non-fuel base revenues of approximately $71.5 million. The request includes recovery of new plant placed into service since 2009. On January 15, 2016, the Company filed its rebuttal testimony modifying the requested increase to $63.3 million. The Company has invoked its statutory right to have its new rates relate back for consumption on and after January 12, 2016, which is the 155th day after the filing. The difference in rates that would have been collected will be surcharged or refunded to customers beginning after the PUCT's final order in Docket No. 44941, which is expected to be in the second quarter of 2016. The PUCT has the authority to require the Company to surcharge or refund such difference over a period not to exceed 18 months. On January 21, 2016, the Company, the City of El Paso, the PUCT staff, the Office of Public Utility Counsel and the Texas Industrial Energy Consumers filed a joint motion to abate the procedural schedule to facilitate settlement talks. This motion was granted. The Company cannot predict the outcome of the rate case at this time.

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Montana Power Station ("MPS") Approvals . The Company has received a Certificate of Convenience and Necessity ("CCN") from the PUCT to construct four natural gas fired generating units at MPS in El Paso County, Texas. The Company also obtained air permits from the Texas Commission on Environmental Quality (the "TCEQ") and the U.S. Environmental Protection Agency (the "EPA"). MPS Units 1 and 2 and associated transmission lines and common facilities were completed and placed into service in March 2015.

Four Corners Generating Station ("Four Corners"). On February 17, 2015, the Company and Arizona Public Service Company ("APS") entered into an asset purchase agreement (the "Purchase and Sale Agreement") providing for the purchase by APS of the Company's interests in Four Corners. The Purchase and Sale Agreement included a projected cash purchase price which will be equal to the net book value of our interest in Four Corners at the date of close. The net book value at June 30, 2016 is expected to approximate $20 million. The Company will also be reimbursed for certain undepreciated capital expenditures, that are projected to approximate $10 million at June 30, 2016. The purchase price will be adjusted downward to reflect APS's assumption of the Company's obligation to pay for future plant decommissioning and mine reclamation expenses estimated at July 6, 2016 to be $7.0 million and $19.3 million, respectively.

Other Required Approvals. The Company has obtained other required approvals for tariffs and approvals as required by the Public Utility Regulatory Act (the "PURA") and the PUCT.

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New Mexico Regulatory Matters

2015 New Mexico Rate Case Filing. On May 11, 2015, the Company filed with the NMPRC (NMPRC Case No. 15-00127-UT) for an annual increase in non-fuel base rates of approximately $8.6 million or 7.1%. The request includes recovery of new plant placed into service since the last time rates were adjusted in 2009. The filing also requests an annual reduction of $15.4 million, or 21.5%, for fuel and purchased power costs recovered in base rates. The reduction in fuel and purchased power rates reflects reduced fuel prices and improvements in system heat rates due to new generating unit additions. Subsequently, the Company reduced its requested increase in non-fuel base rates to approximately $6.4 million. On February 16, 2016, the Hearing Examiner issued a Recommended Decision to the NMPRC proposing an annual increase in non-fuel base rates of approximately $640 thousand. On February 17, 2016, the NMPRC issued an order extending the suspension period in the rate case from March 10, 2016 until April 8, 2016, by which time the NMPRC is expected to either issue a final order with new rates to go into effect in the second quarter of 2016 or again extend the suspension period further to as late as June 10, 2016. All parties will be allowed to file exceptions before the NMPRC ultimately rules on the issues by final order. The Company cannot predict the outcome of the rate case at this time.

Four Corners. On February 17, 2015, the Company and APS entered into the Purchase and Sale Agreement providing for the purchase by APS of the Company's interests in Four Corners. On April 27, 2015, the Company filed an application requesting all necessary regulatory approvals to sell its ownership interest in Four Corners. The anticipated closing date of the sale is July 6, 2016, pending regulatory approval. This case was assigned NMPRC Case No. 15-00109-UT. On February 2, 2016, the Company filed a joint stipulation with the NMPRC reflecting a settlement agreement among the Commission Utility Division Staff, the Company and the New Mexico Attorney General proposing approval of abandonment and sale of its seven percent minority ownership interest in Four Corners Units 4 and 5 and common facilities to APS. An addendum to the joint stipulation was subsequently filed to include non-opposition by other non-stipulating parties. A hearing in the case was held on February 16, 2016, and a final order approving the joint stipulation is expected in the first half of 2016. Based on the joint stipulation and addendum, no significant gain or loss is expected to be realized upon closing of the sale.

5 MW Holloman Air Force Base ("HAFB") Facility CCN. On June 15, 2015, the Company filed a petition with the NMPRC requesting CCN authorization to construct a 5 MW solar-powered generation facility to be located at HAFB in the Company's service territory in New Mexico. The new facility will be a dedicated Company-owned resource serving HAFB. This case was assigned NMPRC Case No. 15-00185-UT. On October 7, 2015, the NMPRC issued a Final Order accepting the Hearing Examiner’s Recommended Decision to approve the CCN, as modified, that the Company shall not seek to recover any revenue requirement associated with the facility from New Mexico jurisdictional customers other than HAFB without prior NMPRC approval.

Issuance of Long-Term Debt and Guarantee of Debt. On October 7, 2015 the Company received approval in NMPRC Case No. 15-00280-UT to issue up to $310 million in new long-term debt; and to guarantee the issuance of up to $65 million of new debt by Rio Grande Resources Trust ("RGRT") to finance future purchases of nuclear fuel and to refinance existing nuclear fuel debt obligations. This approval supersedes prior approvals.

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Federal Regulatory Matters

Public Service Company of New Mexico ("PNM") Transmission Rate Case. On December 31, 2012, PNM filed with FERC to change its method of transmission rate recovery for its transmission delivery services from stated rates to formula rates. The Company takes transmission service from PNM and is among the PNM transmission customers affected by PNM’s shift to formula rates. On March 1, 2013, the FERC issued an order rejecting in part PNM’s filing, and establishing settlement judge and hearing procedures. On March 20, 2015, PNM filed with FERC a settlement agreement and offer of settlement resolving all issues set for hearing in the proceeding. On March 25, 2015, the Chief Judge issued an order granting PNM's motion to implement the settled rates. However, the Company is still awaiting a final decision from the FERC on whether the settlement will be approved. The Company cannot predict the outcome of the case at this time.

Other Required Approvals. The Company has obtained required approvals for rates and tariffs, securities transactions and other approvals as required by the FERC.

United States Department of Energy ("DOE"). The DOE regulates the Company's exports of power to the Comisión Federal de Electricidad in Mexico pursuant to a license and two presidential permits issued by the DOE.

The DOE is authorized to assess operators of nuclear generating facilities a share of the costs of decommissioning the DOE's uranium enrichment facilities and for the ultimate costs of disposal of spent nuclear fuel. See Part II, Item 8, Financial Statements and Supplementary Data, Note E for discussion of spent fuel storage and disposal costs.

Sales for Resale

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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, 2015		December 31, 2014
Regulatory assets
Regulatory tax assets (a)	(b)	$	69,359	$	66,134
Loss on reacquired debt (c)	May 2035	16,632		17,486
Final coal reclamation (d)	(e)	9,520		10,702
Nuclear fuel postload daily financing charge	(e)	4,195		4,127
Unrecovered issuance costs due to reissuance of PCBs (c)	August 2042	827		860
Texas energy efficiency	(f)	25		1,817
Texas 2015 rate case costs	(g)	1,882		169
New Mexico procurement plan costs	(g)	139		139
New Mexico renewable energy credits	(g)	6,258		5,456
New Mexico 2010 FPPCAC audit	(g)	434		434
New Mexico Palo Verde deferred depreciation	(b)	4,568		4,720
New Mexico 2015 rate case costs	(g)	1,288		42
Total regulatory assets		$	115,127	$	112,086
Regulatory liabilities
Regulatory tax liabilities (a)	(b)	$	17,266	$	17,252
Accumulated deferred investment tax credit (h)	(b)	4,011		4,334
New Mexico energy efficiency	(f)	2,238		3,904
Texas military base discount and recovery factor	(i)	788		609
Total regulatory liabilities		$	24,303	$	26,099

________________


(a)	We do not earn a return on these items since the related accumulated deferred income tax assets and liabilities offset.


(b)	The amortization periods for these assets and liabilities are based upon the life of the associated assets or liabilities.


(c)	This item is recovered as a component of the weighted cost of debt and amortized over the life of the related debt issuance.


(d)	This item relates to coal reclamation costs associated with Four Corners. See Part II, Item 8, Financial Statements and Supplementary Data, Note C.


(e)	This item is recovered through fuel recovery mechanisms established by tariff.


(f)	This item is recovered or credited through a recovery factor that is set annually.


(g)	Amortization period is anticipated to be established in next general rate case.


(h)	This item is excluded from rate base.


(i)	This item represents the net asset/net liability related to the military discount which is recovered from non-military customers through a recovery factor.

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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, 2015 (in thousands):



	Gross Plant		Accumulated Depreciation			Net Plant
Nuclear production	$	917,483	$	(304,060	)	$	613,423
Steam and other	907,351		(311,081		)	596,270
Total production	1,824,834		(615,141		)	1,209,693
Transmission	459,188		(256,899		)	202,289
Distribution	1,068,108		(353,713		)	714,395
General	185,862		(53,993		)	131,869
Intangible	78,309		(50,097		)	28,212
Total	$	3,616,301	$	(1,329,843	)	$	2,286,458

Amortization of intangible plant (software) is provided on a straight-line basis over the estimated useful life of the asset (ranging from 3 to 15 years). Effective July 2015, the Company changed the estimated useful life of certain large intangible software systems which decreased depreciation during 2015 by $1.8 million. The expected annual effect for 2016 is approximately $3.6 million. The table below presents the actual and estimated amortization expense for intangible plant for the previous three years and for the next five years (in thousands):



2013	$	7,683
2014	8,051
2015	6,482
2016 (estimated)	5,022
2017 (estimated)	4,602
2018 (estimated)	3,818
2019 (estimated)	3,382
2020 (estimated)	2,935

The Company owns a 15.8% interest in each of the three nuclear generating units and common facilities at Palo Verde, in Wintersburg, Arizona. The Palo Verde Participants include the Company and six other utilities: APS, Southern California Edison Company ("SCE"), PNM, Southern California Public Power Authority, Salt River Project Agricultural Improvement and Power District ("SRP") and the Los Angeles Department of Water and Power.

Other jointly-owned utility plant includes a 7% interest in Units 4 and 5 at 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, 2015 and 2014 is as follows (in thousands):



	December 31, 2015						December 31, 2014
	Palo Verde			Other			Palo Verde			Other
Electric plant in service	$	917,483		$	229,627		$	874,817		$	219,318
Accumulated depreciation	(304,060		)	(181,886		)	(286,585		)	(176,492		)
Construction work in progress	48,938			9,528			55,632			6,900
Total	$	662,361		$	57,269		$	643,864		$	49,726

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Palo Verde

The operation of Palo Verde and the relationship among the Palo Verde Participants is governed by the Arizona Nuclear Power Project Participation Agreement (the "ANPP Participation Agreement"). APS serves as operating agent for Palo Verde, and under the ANPP Participation Agreement, the Company has limited ability to influence operations and costs at Palo Verde. Pursuant to the ANPP Participation Agreement, the Palo Verde Participants share costs and generating entitlements in the same proportion as their percentage interests in the generating units, and each participant is required to fund its share of fuel, other operations, maintenance and capital costs. The Company’s share of direct expenses in Palo Verde and other jointly-owned utility plants is reflected in fuel expense, other operations expense, maintenance expense, miscellaneous other deductions, and taxes other than income taxes in the Company’s statements of operations. The ANPP Participation Agreement provides that if a participant fails to meet its payment obligations, each non-defaulting participant shall pay its proportionate share of the payments owed by the defaulting participant. Because it is impracticable to predict defaulting participants, the Company cannot estimate the maximum potential amount of future payment, if any, which could be required under this provision.

Nuclear Regulatory Commission ("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.

Palo Verde Operating Licenses. Operation of each of the three Palo Verde Units requires an operating license from the NRC. The NRC issued full power operating licenses for Unit 1 in June 1985, Unit 2 in April 1986 and Unit 3 in November 1987, and issued renewed operating licenses for each of the three units in April 2011, which extended the licenses for Units 1, 2 and 3 to June 2045, April 2046 and November 2047, respectively.

Decommissioning. Pursuant to the ANPP Participation Agreement and federal law, the Company funds its share of the estimated costs to decommission Palo Verde Units 1, 2 and 3, including the Common Facilities, through the term of their respective operating licenses and is required to maintain a minimum accumulation and funding level in its decommissioning account at the end of each annual reporting period during the life of the plant. The Company has established external trusts with an independent trustee, which enables the Company to record a current deduction for federal income tax purposes for most of the amounts funded. At December 31, 2015, the Company’s decommissioning trust fund had a balance of $239.0 million, which is above its minimum funding level. The Company monitors the status of its decommissioning funds and adjusts its deposits, if necessary.

Decommissioning costs are estimated every three years based upon engineering cost studies performed by outside engineers retained by APS. In December 2013, the Palo Verde Participants approved the 2013 Palo Verde decommissioning study (the "2013 Study"). The 2013 Study estimated that the Company must fund approximately $380.7 million (stated in 2013 dollars) to cover its share of decommissioning costs which was an increase in decommissioning costs of $23.3 million (stated in 2013 dollars) from the 2010 Palo Verde decommissioning study. However, because the cash flows from the 2013 Study were less than the inflated amounts from the 2010 Study, the effect of this change lowered the ARO by $1.9 million which lowered annual expenses starting in January 2014. Although the 2013 Study was based on the latest available information, there can be no assurance that decommissioning cost estimates will not increase in the future or that regulatory requirements will not change. In addition, until a new low-level radioactive waste repository opens and operates for a number of years, estimates of the cost to dispose of low-level radioactive waste are subject to significant uncertainty. While the Company attempts to seek amounts in rates to meet its decommissioning obligations, it is not able to conclude given the evidence available to it now that it is probable these costs will continue to be collected over the period until decommissioning begins in 2044. The Company is ultimately responsible for these costs and its future actions combined with future decisions from regulators will determine how successful the Company is in this effort.

Spent Nuclear Fuel and Waste Disposal. Pursuant to the Nuclear Waste Policy Act of 1982, as amended in 1987 (the "NWPA"), the DOE is legally obligated to accept and dispose of all spent nuclear fuel and other high-level radioactive waste generated by all domestic power reactors by 1998. The DOE's obligations are reflected in a contract for Disposal of Spent Nuclear Fuel and/or High-Level Radioactive Waste (the "Standard Contract") with each nuclear power plant. The DOE failed to begin accepting spent nuclear fuel by 1998. On December 19, 2012, APS, acting on behalf of itself and the Palo Verde Participants, filed a second breach of contract lawsuit against the DOE. This lawsuit sought to recover damages incurred due to the DOE’s failure to accept Palo Verde’s spent nuclear fuel for the period beginning January 1, 2007 through June 30, 2011. On August 18, 2014, APS and the DOE entered into a settlement agreement, stipulating to a dismissal of the lawsuit and payment of $57.4 million by the DOE to the Palo Verde Participants for certain specified costs incurred by Palo Verde during the period January 1, 2007 through June 30, 2011. On October 8, 2014, the Company received approximately $9.1 million, representing its share of the award. The majority of the award was refunded to customers through the applicable fuel adjustment clauses. On October 31, 2014, APS acting on behalf of itself

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and the Palo Verde Participants, submitted to the government an additional request for reimbursement of spent nuclear fuel storage costs for the period July 1, 2011 through June 30, 2014. The accepted claim amount was $42.0 million. On June 1, 2015, the Company received approximately $6.6 million, representing its share of the award. The majority of the award was credited to customers through the applicable fuel adjustment clauses in March 2015. Thereafter APS will file annual claims for the period July 1 of the then-previous year to June 30 of the then-current year. On November 2, 2015, APS filed a $12.0 million claim for the period July 1, 2014 through June 30, 2015. In February 2016, the DOE notified APS of the approval of the claim. Funds related to this claim are expected to be received in the second quarter of 2016. The Company's share of this claim is approximately $1.9 million.

On October 16, 2014, the NRC issued Volume 3 of the safety evaluation report developed as part of the Yucca Mountain construction authorization application. This volume addresses repository safety after permanent closure, and its issuance is a key milestone in the Yucca Mountain licensing process. Volume 3 contains the NRC staff’s finding that the DOE’s repository design meets the requirements that apply after the repository is permanently closed, including but not limited to the post-closure performance objectives in NRC’s regulations.

Publication of Volumes 3 and 4 does not signal whether or when the NRC might authorize construction of the repository. The Company cannot predict when spent fuel shipments to the DOE will commence.

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power plant licenses and renewals that went into effect when the D.C. Circuit issued its June 2012 decision. The August 2014 final rule has been subject to continuing legal challenges before the NRC and the Court of Appeals.

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 was recovered by the Company through applicable fuel adjustment clauses. In June 2012, 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 and on May 12, 2014, APS was notified by the DOE that, effective May 16, 2014, the one-mill fee would be suspended. Electricity generated and sold prior to May 16, 2014 remained subject to the one-mill fee.

The NRC has issued a series of interim staff guidance documents regarding implementation of these requirements. Palo Verde has met the NRC's imposed deadlines for installation of equipment to address these requirements, but has minor additional work to perform in 2016. Palo Verde has spent approximately $125 million (the Company's share is $19.7 million) on capital enhancements related to these requirements as of December 31, 2015.

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 $13.5 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 $2.8 billion of "all risk" nuclear property insurance. The insurance provides coverage for property damage and decontamination at Palo Verde. For covered incidents involving property damage not accompanied by a release of radioactive material, the policy's coverage limit is $2.25 billion. The Company has also secured insurance against portions of any increased cost of generation or purchased power and business interruption resulting from a sudden and unforeseen outage of any of the three units. The insurance coverage discussed in this and the previous paragraph is subject to certain policy conditions and exclusions. A mutual insurance company whose members are utilities with nuclear facilities issues these policies. If losses at any nuclear facility covered by this mutual insurance company were to exceed the accumulated funds for these insurance programs, the Company could be assessed retrospective premium adjustments of up to $12.7 million for the current policy period.

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Four Corners

The Company owns a 7% interest in Units 4 and 5 at Four Corners and shares power entitlements and allocated costs with APS, the operating agent, and the other Four Corners participants. The Company notified the other participants in 2013 that it would not continue in Four Corners after the termination of the 50-year contractual term of the participation agreement in July 2016 but that it would offer to sell its interest to them in order to facilitate their decision to extend the life of the plant. On February 17, 2015, the Company and APS entered into the Purchase and Sale Agreement providing for the purchase by APS of the Company’s interests in Four Corners. The cash purchase price is equal to the net book value of the Company’s interest in Four Corners at the date of closing. The anticipated closing date for the sale is July 6, 2016, pending regulatory approval. See Part II, Item 8, Financial Statements and Supplementary Data, Note C. The purchase price will be adjusted downward to reflect APS’s assumption in the Agreement of the Company’s obligation to pay for future plant decommissioning and mine reclamation expenses. At the closing, APS will also reimburse the Company for the undepreciated value of certain capital expenditures made prior thereto. APS will assume responsibility for all capital expenditures made after July 2016 and, with certain exceptions, any pre-2016 capital expenditures to be put into service following the closing. In addition, APS will indemnify the Company against liabilities and costs related to the future operation of Four Corners. Included in the Company's balance sheet at December 31, 2015 are obligations of $6.7 million and $19.3 million for plant decommissioning and mine reclamation costs, respectively, which the Company expects to pay at closing in accordance with the Agreement. Four Corners is expected to continue to provide energy to serve the native load up to the closing date. See Part II, Item 8, Financial Statements and Supplementary Data, Note C for a discussion of regulatory filings associated with Four Corners.

F. Accounting for Asset Retirement Obligation

The Company complies with the FASB guidance for ARO. This guidance affects the accounting for the decommissioning of the Company’s Palo Verde and Four Corners Stations and the method used to report the decommissioning obligation. The Company also complies with the FASB guidance for conditional ARO which primarily affects the accounting for the disposal obligations of the Company’s fuel oil storage tanks, water wells, evaporative ponds and asbestos found at the Company’s gas-fired generating plants. The Company’s ARO are subject to various assumptions and determinations such as: (i) whether a legal obligation exists to remove assets; (ii) estimation of the fair value of the costs of removal; (iii) when final removal will occur; (iv) future changes in decommissioning cost escalation rates; and (v) the credit-adjusted interest rates to be utilized in discounting future liabilities. Changes that may arise over time with regard to these assumptions and determinations will change amounts recorded in the future as an expense for ARO. The Company records the increase in the ARO due to the passage of time as an operating expense (accretion expense). If the Company incurs or assumes any liability in retiring any asset at the end of its useful life without a legal obligation to do so, it will record such retirement costs as incurred.

The ARO liability for Palo Verde is based upon the estimated cost of decommissioning the plant from the 2013 Palo Verde decommissioning study. See Part II, Item 8, Financial Statements and Supplementary Data, Note E. The ARO liability is calculated by adjusting the estimated decommissioning costs for spent fuel storage and a profit margin and market-risk premium factor. The resulting costs are escalated over the remaining life of the plant and finally discounted using a credit-risk adjusted discount rate. As Palo Verde approaches the end of its estimated useful life, the difference between the ARO liability and future current cost estimates will narrow over time due to the accretion of the ARO liability. Because the DOE is obligated to assume responsibility for the permanent disposal of spent fuel, spent fuel costs have not been included in the ARO calculation. The Company maintains six external trust funds with an independent trustee that are legally restricted to settling its ARO at Palo Verde. The fair value of the funds at December 31, 2015 is $239.0 million.

The FASB guidance requires the Company to revise its previously recorded ARO for any changes in estimated cash flows including changes in estimated probabilities related to timing of settlements. Any changes that result in an upward revision to estimated cash flows shall be treated as a new liability. Any downward revisions to the estimated cash flows result in a reduction to the previously recorded ARO. In December 2013, the Company implemented the 2013 Palo Verde decommissioning study, and as a result, revised its ARO related to Palo Verde to decrease its estimated cash flows from the 2010 Study to the 2013 Study (see Part II, Item 8, Financial Statements and Supplementary Data, Note E). The assumptions used to calculate the Palo Verde ARO liability are as follows:



	Escalation Rate		Credit-Risk Adjusted Discount Rate
Original ARO liability	3.60	%	9.50	%
Incremental ARO liability	3.60	%	6.20	%

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An analysis of the activity of the Company’s total ARO liability from January 1, 2013 through December 31, 2015, including the effects of each year’s estimate revisions, is presented below. In 2014, the estimate revision includes an adjustment to Four Corners due to the early recognition of the obligation resulting from the purchase agreement with APS. 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.



	2015		2014		2013
ARO liability at beginning of year	$	74,577	$	65,214	$	62,784
Liabilities incurred	189		—		—
Liabilities settled	—		—		(36		)
Revisions to estimate	—		3,561		(3,401		)
Accretion expense	6,855		5,802		5,867
ARO liability at end of year	$	81,621	$	74,577	$	65,214

The Company has transmission and distribution lines which are operated under various property easement agreements. If the easements were to be released, the Company may have a legal obligation to remove the lines; however, the Company has assessed the likelihood of this occurring as remote. The majority of these easements include renewal options which the Company routinely exercises. The amount of cost of removal collected in rates for non-legal liabilities has not been material.

G. Common Stock

Overview

The Company’s common stock has a stated value of $1 per share, with no cumulative voting rights or preemptive rights. Holders of the common stock have the right to elect the Company’s directors and to vote on other matters.

Long-Term Incentive Plan

On May 29, 2014, the Company’s shareholders approved an amended and restated stock-based long-term incentive plan (the "Amended and Restated 2007 LTIP") and authorized the issuance of up to 1.7 million shares of the Company's common stock for the benefit of directors and employees. Under the Amended and Restated 2007 LTIP, shares of the Company's common stock may be issued through the award or grant of non-statutory stock options, incentive stock options, stock appreciation rights, restricted stock, bonus stock, performance stock, cash-based awards and other stock-based awards. The Company may issue new shares, purchase shares on the open market, or issue shares from shares of the Company's common stock the Company has repurchased to meet the share requirements of the Amended and Restated 2007 LTIP. Beginning in 2015, shares of the Company's common stock issued for employee benefit and stock incentive plans have been issued from the shares repurchased and held in treasury stock. As discussed in Part II, Item 8, Financial Statements and Supplementary Data, Note A, the Company accounts for its stock-based long-term incentive plan under the FASB guidance for stock-based compensation.

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 had no stock options outstanding as of December 31, 2014 and December 31, 2015.

The intrinsic value of stock options exercised in 2013 was $0.3 million. No options were forfeited, vested or expired during 2015, 2014 and 2013. No compensation cost was recognized in 2015, 2014 and 2013 for stock options.

Restricted Stock with Service Condition and Other Stock-Based Awards. The Company has awarded restricted stock and other stock-based awards under its long-term incentive plan. Restrictions from resale on restricted stock awards generally lapse and awards vest over periods of one to three years. The market value of the unvested restricted stock at the date of grant is amortized to expense over the restriction period net of anticipated forfeitures.

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Other stock-based awards are fully vested and are expensed at fair value on the date of grant. Previously directors could elect to receive retainers and meeting fees in cash, restricted stock, or a combination of cash and stock. On May 29, 2014, the Board of Directors voted to revise the terms of the restricted stock awards granted to directors in lieu of cash for retainers and meeting fees. Stock elections by directors in lieu of cash for retainer and meeting fees are now fully vested and are expensed at fair value on the date of grant. The modification to 13,863 outstanding restricted stock awards granted to directors resulted in forfeiture of those awards and the granting of new awards which were fully vested and expensed at $37.81 per share, the fair value on the date of grant. Effective fiscal year ended December 31, 2015, other stock-based awards are not included in the tables below.

The expense, deferred tax benefit, and current tax expense recognized related to restricted stock and other stock-based awards in 2015, 2014 and 2013 is presented below (in thousands):



	2015		2014		2013

Expense (a)	$	2,755	$	3,471	$	2,458
Deferred tax benefit	964		1,215		860
Current tax benefit recognized	43		39		109

_____________________

(a) Any capitalized costs related to these expenses is less than $0.3 million for all years.

The aggregate intrinsic value and fair value at grant date of restricted stock and other stock-based awards which vested in 2015, 2014 and 2013 is presented below (in thousands):



	2015		2014		2013

Aggregated intrinsic value	$	3,451	$	3,441	$	2,077
Fair value at grant date	3,327		3,330		1,765

The unvested restricted stock transactions for 2015 are presented below:



	Total Shares		Weighted Average Grant Date Fair Value		Unrecognized Compensation Expense (a)		Aggregate Intrinsic Value
					(In thousands)		(In thousands)
Restricted shares outstanding at December 31, 2014	124,297		$	35.81
Stock awards	72,187		37.17
Vested	(92,188	)	36.09
Forfeitures	(13,086	)	35.76
Restricted shares outstanding at December 31, 2015	91,210		36.61		$	1,397	$	3,512

_______________________

(a) The unrecognized compensation expense is expected to be recognized over the weighted average remaining contractual term of the outstanding restricted stock of approximately one year.

The weighted average fair value per share at grant date for restricted stock and other stock-base awards granted during 2015, 2014 and 2013 were:



	2015		2014		2013
Weighted average fair value per share	$	37.17	$	36.95	$	35.48

The holder of a restricted stock award has rights as a shareholder of the Company, including the right to vote and receive cash dividends on restricted stock.

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Restricted Stock with a Performance Condition. On December 15, 2015, the Company issued a stock based retention grant to the Chief Executive Officer of 27,624 shares in accordance with of the Company's Amended and Restated 2007 LTIP that is eligible for vesting based on the achievement of certain performance conditions and a five year service period, as stated in the employment agreement. As of December 31, 2015, the adjusted grant date fair value for the award was $30.43, unrecognized compensation expense was $0.7 million, and the intrinsic value was $1.1 million. For 2015, the Company recognized $6,000 as compensation expense and $2,000 of deferred tax benefit related to this grant.

Restricted Stock with a Market Condition (Performance Shares). The Company has granted performance share awards to certain officers under the Company’s Amended and Restated 2007 LTIP, which provides for issuance of Company stock based on the achievement of certain performance criteria over a three-year period. The payout varies between 0% to 200% of performance share awards.

Detail of performance shares vested follows:



Date Vested	Payout Ratio		Performance Shares Awarded	Compensation Costs Expensed		Period Compensation Costs Expensed	Aggregated Intrinsic Value
				(In thousands)			(In thousands)
January 27, 2016	0	%	0	$	851	2013-2015	$	—
February 20, 2015	0	%	0	1,502		2012-2014	—
February 18, 2014	0	%	0	954		2011-2013	—
January 29, 2013	150.0	%	64,275	849		2010-2012	2,176

In 2016, 2017 and 2018, subject to meeting certain performance criteria, additional performance shares could be awarded. In accordance with the FASB guidance related to stock-based compensation, the Company recognizes the related compensation expense by ratably amortizing the grant date fair value of awards over the requisite service period and the compensation expense is only adjusted for forfeitures. Excluding the 2013 award, the actual number of shares to be issued can range from zero to 155,970 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, 2014	121,481		$	30.71
Performance share awards	52,948		35.72
Performance shares expired	(57,299	)	29.51
Performance shares forfeited	(14,618	)	35.13
Performance shares outstanding at December 31, 2015	102,512		33.34		$	1,112	$	3,947

_______________________

(a) The unrecognized compensation expense is expected to be recognized over the weighted average remaining contractual term of the awards of approximately one year.

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A summary of information related to performance shares for 2015, 2014 and 2013 is presented below:



	2015		2014		2013
Weighted average per share grant date fair value per share of performance shares awarded	$	35.72	$	26.36	$	34.69
Fair value of performance shares vested (in thousands)	—		—		849
Intrinsic value of performance shares vested (in thousands) (a)	—		—		1,450
Compensation expense (in thousands) (b)	1,042		1,181		1,188
Deferred tax benefit related to compensation expense (in thousands)	365		413		416

_____________________

(a) Based on a 100% performance level.

(b) Includes adjustments for forfeiture of performance share awards by certain executives.

Repurchase Program

No shares of the Company's common stock were repurchased during the twelve months ended December 31, 2015. Detail regarding the Company's stock repurchase program are presented below:

______________________


(a)	Represents repurchased shares and cost since inception of the stock repurchase program in 1999.

(b)

Shares repurchased does not include 86,735 treasury shares related to employee compensation arrangements outside of the Company's repurchase programs. Beginning in 2015, shares of the Company's common stock issued for employee benefit and stock incentive plans have been issued from the shares repurchased and held in treasury stock. The Company awarded 108,085 shares out of treasury stock during 2015.

The Company may in the future make purchases of shares of its common stock pursuant to its authorized program in open market transactions at prevailing prices and may engage in private transactions where appropriate. The repurchased shares will be available for issuance under employee benefit and stock incentive plans, or may be retired.

Dividend Policy

On December 30, 2015, the Company paid $11.9 million in quarterly cash dividends to shareholders. The Company paid a total of $47.1 million, $44.6 million and $42.0 million in cash dividends during the twelve months ended December 31, 2015, 2014 and 2013, respectively. On January 28, 2016, the Board of Directors declared a quarterly cash dividend of $0.295 per share payable on March 31, 2016 to shareholders of record as of the close of business on March 15, 2016.

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Basic and Diluted Earnings Per Share

The FASB guidance requires the Company to include share-based compensation awards that qualify as participating securities in both basic and diluted earnings per share to the extent they are dilutive. A share-based compensation award is considered a participating security if it receives non-forfeitable dividends or may participate in undistributed earnings with common stock. The Company awards unvested restricted stock which qualifies as a participating security. The basic and diluted earnings per share are presented below:



	Years Ended December 31,
	2015			2014			2013
Weighted average number of common shares outstanding:
Basic number of common shares outstanding	40,274,986			40,190,991			40,114,594
Dilutive effect of unvested performance awards	33,576			20,726			12,053
Diluted number of common shares outstanding	40,308,562			40,211,717			40,126,647
Basic net income per common share:
Net income	$	81,918		$	91,428		$	88,583
Income allocated to participating restricted stock	(243		)	(301		)	(254		)
Net income available to common shareholders	$	81,675		$	91,127		$	88,329
Diluted net income per common share:
Net income	$	81,918		$	91,428		$	88,583
Income reallocated to participating restricted stock	(243		)	(301		)	(254		)
Net income available to common shareholders	$	81,675		$	91,127		$	88,329
Basic net income per common share:
Distributed earnings	$	1.165		$	1.105		$	1.045
Undistributed earnings	0.865			1.165			1.155
Basic net income per common share	$	2.030		$	2.270		$	2.200
Diluted net income per common share:
Distributed earnings	$	1.165		$	1.105		$	1.045
Undistributed earnings	0.865			1.165			1.155
Diluted net income per common share	$	2.030		$	2.270		$	2.200

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:



	Year Ended December 31,
	2015	2014	2013
Restricted stock awards	56,375	60,455	51,489
Performance shares (a)	66,804	96,208	115,044

_____________________


(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.

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H. Accumulated Other Comprehensive Income (Loss)



Changes in Accumulated Other Comprehensive Income (Loss) (net of tax) by component are presented below (in thousands):
		Unrecognized Pension and Post-retirement Benefit Costs			Net Unrealized Gains (Losses) on Marketable Securities			Net Losses on Cash Flow Hedges			Accumulated Other Comprehensive Income (Loss)

Balance at December 31, 2012		$	(75,737	)	$	22,194		$	(12,541	)	$	(66,084	)
	Other comprehensive income before reclassifications	51,371			14,482			—			65,853
	Amounts reclassified from accumulated other comprehensive income (loss)	3,036			(436		)	243			2,843
Balance at December 31, 2013		(21,330		)	36,240			(12,298		)	2,612
	Other comprehensive income (loss) before reclassifications	(12,628		)	8,694			—			(3,934		)
	Amounts reclassified from accumulated other comprehensive income (loss)	(926		)	(5,977		)	224			(6,679		)
Balance at December 31, 2014		(34,884		)	38,957			(12,074		)	(8,001		)
	Other comprehensive income (loss) before reclassifications	3,777			(2,255		)	—			1,522
	Amounts reclassified from accumulated other comprehensive income (loss)	1,238			(8,937		)	264			(7,435		)
Balance at December 31, 2015		$	(29,869	)	$	27,765		$	(11,810	)	$	(13,914	)

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Amounts reclassified from accumulated other comprehensive income (loss) for the twelve months ended December 31, 2015, 2014 and 2013 are as follows (in thousands):



Details about Accumulated Other Comprehensive Income (Loss) Components		2015			2014			2013			Affected Line Item in the Statement of Operations

Amortization of pension and post-retirement benefit costs:
	Prior service benefit	$	6,574		$	7,659		$	5,560		(a)
	Net loss	(8,622		)	(6,182		)	(10,472		)	(a)
		(2,048		)	1,477			(4,912		)	(a)
	Income tax effect	810			(551		)	1,876
		(1,238		)	926			(3,036		)	(a)

Marketable securities:
	Net realized gain on sale of securities	11,114			7,350			553			Investment and interest income, net
		11,114			7,350			553			Income before income taxes
	Income tax effect	(2,177		)	(1,373		)	(117		)	Income tax expense
		8,937			5,977			436			Net income

Loss on cash flow hedge:
	Amortization of loss	(467		)	(438		)	(411		)	Interest on long-term debt and RCF
		(467		)	(438		)	(411		)	Income before income taxes
	Income tax effect	203			214			168			Income tax expense
		(264		)	(224		)	(243		)	Net income

	Total reclassifications	$	7,435		$	6,679		$	(2,843	)

(a) These items are included in the computation of net periodic benefit cost. See Part II, Item 8, Financial Statements and Supplementary Data, Note M for additional information.

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NOTES TO FINANCIAL STATEMENTS

I. Long-Term Debt and Financing Obligations

Outstanding long-term debt and financing obligations are as follows:



	December 31,
	2015			2014
	(In thousands)
Long-Term Debt:
Pollution Control Bonds (1):
7.25% 2009 Series A refunding bonds, due 2040 (7.46% effective interest rate)	$	63,500		$	63,500
4.50% 2012 Series A refunding bonds, due 2042 (4.63% effective interest rate)	59,235			59,235
7.25% 2009 Series B refunding bonds, due 2040 (7.49% effective interest rate)	37,100			37,100
1.875% 2012 Series A refunding bonds, due 2032 (2.35% effective interest rate)	33,300			33,300
Total Pollution Control Bonds	193,135			193,135
Senior Notes (2):
6.00% Senior Notes, net of discount, due 2035 (7.12% effective interest rate)	398,069			398,021
7.50% Senior Notes, net of discount, due 2038 (7.67% effective interest rate)	148,838			148,818
3.30% Senior Notes, net of discount, due 2022 (3.43% effective interest rate)	149,766			149,737
5.00% Senior Notes, net of discount, due 2044 (5.10% effective interest rate)	149,476			149,468
Total Senior Notes	846,149			846,044
RGRT Senior Notes (3):
3.67% Senior Notes, Series A, due 2015 (3.87% effective interest rate)	—			15,000
4.47% Senior Notes, Series B, due 2017 (4.62% effective interest rate)	50,000			50,000
5.04% Senior Notes, Series C, due 2020 (5.16% effective interest rate)	45,000			45,000
Total RGRT Senior Notes	95,000			110,000
Total long-term debt	1,134,284			1,149,179
Financing Obligations:
Revolving Credit Facility ($141,738 due in 2016) (4)	141,738			14,532
Total long-term debt and financing obligations	1,276,022			1,163,711
Current Portion (amount due within one year):
Current maturities of long term debt	—			(15,000		)
Short-term borrowings under the revolving credit facility	(141,738		)	(14,532		)
	$	1,134,284		$	1,134,179

_____________________


(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 Part II, Item 8, Financial Statements and Supplementary Data, Note O. This amortization is included in the effective interest rate of the 6.00% Senior Notes.

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NOTES TO FINANCIAL STATEMENTS

The 7.50% Senior Notes have an aggregate principal amount of $150.0 million and were issued in June 2008. The proceeds, net of a $1.3 million discount, were used to repay short-term borrowings of $44.0 million, fund capital expenditures and for other general corporate purposes.

The 3.30% Senior Notes have an aggregate principal amount of $150.0 million 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.

The 5.00% Senior Notes have an aggregate principal amount of $150.0 million and were issued in December 2014. The proceeds, net of a $0.5 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"). In August 2015, $15.0 million of these Notes matured and were paid with borrowings from the RCF. 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 pays interest on the Notes on February 15, and August 15 of each year until maturity. RGRT may redeem the Notes, in whole or in part, at any time at a redemption price equal to 100% of the principal amount to be redeemed together with the interest on such principal amount accrued to the date of redemption, plus a make-whole amount based on the prevailing market interest rates. The agreement requires compliance with certain covenants, including a total debt to capitalization ratio. The Company was in compliance with these requirements throughout 2015.

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 RCF.


(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 2015. In August 2015, $15.0 million aggregate principal amount of Series A 3.67% Senior Notes of RGRT matured and were paid utilizing borrowings under the RFC. As of December 31, 2015, the total amount borrowed by RGRT was $33.7 million for nuclear fuel under the RCF. As of December 31, 2015, $108.0 million of borrowings were outstanding under this facility for working capital and general corporate purposes. The weighted average interest rate on the RCF was 1.4% as of December 31, 2015.

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NOTES TO FINANCIAL STATEMENTS

As of December 31, 2015, the scheduled maturities for the next five years of long-term debt are as follows (in thousands):




2016	$	—
2017	83,300
2018	—
2019	—
2020	45,000

The $33.7 million outstanding on the RCF for nuclear fuel financing purposes is anticipated to be paid in 2016.

J. Income Taxes

The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and liabilities at December 31, 2015 and 2014 are presented below (in thousands):



	December 31,
	2015			2014
Deferred tax assets:
Benefit of tax loss carryforwards	$	35,153		$	—
Alternative minimum tax credit carryforward	16,620			17,701
Pensions and benefits	61,673			64,407
Asset retirement obligation	28,042			25,725
Deferred fuel	1,488			—
Other	15,421			15,768
Total gross deferred tax assets	158,397			123,601
Deferred tax liabilities:
Plant, principally due to depreciation and basis differences	(608,738		)	(536,264		)
Decommissioning	(41,100		)	(40,373		)
Deferred fuel	—			(3,531		)
Other	(3,796		)	(3,630		)
Total gross deferred tax liabilities	(653,634		)	(583,798		)
Net accumulated deferred income taxes	$	(495,237	)	$	(460,197	)

Based on the average annual book income before taxes for the prior three years, excluding the effects of unusual or infrequent items, the Company believes that the deferred tax assets will be fully realized at current levels of book and taxable income.

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EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

The Company recognized income tax expense for 2015, 2014 and 2013 as follows (in thousands):



	Years Ended December 31,
	2015			2014			2013
Income tax expense:
Federal:
Current	$	2,319		$	(1,250	)	$	(2,877	)
Deferred	32,819			38,810			45,024
Total federal income tax	35,138			37,560			42,147
State:
Current	1,730			3,209			1,854
Deferred	(1,650		)	641			(414		)
Total state income tax	80			3,850			1,440
Generation (amortization) of accumulated investment tax credits	(323		)	(322		)	68
Total income tax expense	$	34,895		$	41,088		$	43,655

As of December 31, 2015, the Company had $16.6 million of AMT credit carryforwards that have an unlimited life. As of December 31, 2015, the Company had $34.1 million of federal and $1.1 million of state tax loss carryforwards. If unused, both the federal and state tax loss carryforwards have lives of 20 years and 5 years respectively.

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):



	Years Ended December 31,
	2015			2014			2013
Federal income tax expense computed on income at statutory rate	$	40,885		$	46,381		$	46,283
Difference due to:
State taxes, net of federal benefit	52			1,902			936
AEFUDC	(2,345		)	(3,757		)	(2,149		)
Permanent tax differences	(2,898		)	(2,921		)	(1,153		)
Other	(799		)	(517		)	(262		)
Total income tax expense	$	34,895		$	41,088		$	43,655
Effective income tax rate	29.9		%	31.0		%	33.0		%

The Company files income tax returns in the United States federal jurisdiction and in the states of Texas, New Mexico and Arizona. The Company is no longer subject to tax examination by the taxing authorities in the federal and New Mexico jurisdictions for years prior to 2011. The Company is currently under audit in Texas for tax years 2007 through 2011 and in Arizona for tax years 2009 through 2012.

On December 18, 2015, the President signed the Protecting Americans from Tax Hikes Act of 2015. This act included the extension of bonus depreciation and certain credits which impacted the Company. The Company recorded the impacts of the law change in December 2015, which did not have a material impact on the financial position of the Company.

The FASB guidance prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. In January 2010, the Company filed for a change of accounting method with the Internal Revenue Service ("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 2013 federal income tax returns. In 2013, a $4.5 million decrease was made to the reserve related to the change in accounting method. The decrease was primarily the result of the completion of IRS audits for tax years 2009 to 2012. In September 2014, the Company received an Issue Resolution Agreement ("IRA") from IRS regarding the generation repairs deduction for all years. In the IRA, the IRS declared that the method used by the Company to calculate the generation repair deduction was substantially the same as the method outlined in the Revenue Procedure and declared that therefore no

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EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

adjustment to the deduction taken in previous tax returns by the Company was required. As a result of the IRA, in 2014 the Company recorded a $2.8 million decrease to eliminate the balance of the reserve related to the change in accounting method. The Company recorded an unrecognized tax position of $0.8 million, $2.1 million, and $0.5 million in 2015, 2014, and 2013, respectively, related to depreciation and other amounts deducted in current and prior year Texas franchise tax returns. The Company recorded a decrease of $1.3 million (net of an increase of $0.4 million) in 2014 and an increase 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, which have been settled through audit. A reconciliation of the December 31, 2015, 2014 and 2013 amounts of unrecognized tax benefits are as follows (in thousands):



	2015		2014			2013
Balance at January 1	$	5,200	$	7,200		$	9,800
Additions for tax positions related to the current year	500		300			600
Reductions for tax positions related to the current year	—		—			—
Additions for tax positions of prior years	300		2,200			1,700
Reductions for tax positions of prior years	—		(4,500		)	(4,900		)
Balance at December 31	$	6,000	$	5,200		$	7,200

If recognized, $3.6 million of the unrecognized tax position at December 31, 2015, would affect the effective tax rate. The Company recognized income tax expense for an unrecognized tax position of $0.8 million for the year ended December 31, 2015.

The Company recognizes in tax expense interest and penalties related to tax benefits that have not been recognized. For the years ended December 31, 2015, 2014, and 2013 the Company recognized interest expense of $0.2 million, $0.1 million, and $0.2 million, respectively. The Company had approximately $0.7 million and $0.5 million accrued for the payment of interest and penalties at December 31, 2015 and 2014, respectively.

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NOTES TO FINANCIAL STATEMENTS

K. Commitments, Contingencies and Uncertainties

Power Purchase and Sale Contracts

To supplement its own generation and operating reserve requirements and to meet required renewable portfolio standards, the Company engages in power purchase arrangements that may vary in duration and amount based on an evaluation of the Company’s resource needs, the economics of the transactions, and specific renewable portfolio requirements. The Company has entered into the following significant agreements with various counterparties for the purchase and sale of electricity:



						Commercial
						Operation
Type of Contract	Counterparty	Quantity			Term	Date
Power Purchase and Sale Agreement	Freeport		25	MW	December 2008 through December 2016	N/A
Power Purchase and Sale Agreement	Freeport		100	MW	June 2006 through December 2021	N/A
Power Purchase Agreement	Hatch Solar Energy Center I, LLC		5	MW	July 2011 through June 2036	July 2011
Power Purchase Agreement	NRG		20	MW	August 2011 through August 2031	August 2011
Power Purchase Agreement	SunE EPE1, LLC		10	MW	June 2012 through June 2037	June 2012
Power Purchase Agreement	SunE EPE2, LLC		12	MW	May 2012 through May 2037	May 2012
Power Purchase Agreement	Macho Springs Solar, LLC		50	MW	May 2014 through April 2034	May 2014
Power Purchase Agreement	Newman Solar LLC		10	MW	December 2014 through November 2044	December 2014

The Company has a firm Power Purchase and Sale Agreement with Freeport-McMoran Copper & Gold Energy Services LLC ("Freeport") that provides for Freeport to deliver energy to the Company from the Luna Energy Facility (a natural gas-fired combined cycle generation facility located in Luna County, New Mexico) and for the Company to deliver a like amount of energy at Greenlee, Arizona. The Company may purchase the quantities noted in the table above at a specified price at times when energy is not exchanged under the Power Purchase and Sale Agreement. The agreement was approved by the FERC and will continue through an initial term ending December 31, 2021, with subsequent rollovers until terminated. Upon mutual agreement, the Power Purchase and Sale Agreement allows the parties to increase the amount of energy that is purchased and sold under the agreement. The parties have agreed to increase the amount up to 125 MW through December 2016.

The Company has entered into several power purchase agreements to help meet its renewable portfolio requirements. Namely, the Company has a 25-year purchase power agreement with Hatch Solar Energy Center I, LLC to purchase all of the output from a solar photovoltaic plant located in southern New Mexico which began commercial operation in July 2011. In June 2015, the Company entered into a consent agreement with Hatch Solar Energy Center 1, LLC to provide for additional or replacement photovoltaic modules. The Company also entered into a 20-year contract with NRG Solar Roadrunner LLC ("NRG") to purchase all of the output of a solar photovoltaic plant built in southern New Mexico which began commercial operation in August 2011. In addition, the Company has 25-year purchase power agreements to purchase all of the output of two additional solar photovoltaic plants located in southern New Mexico, SunE EPE1, LLC and SunE EPE2, LLC which began commercial operation in June 2012 and May 2012, respectively.

Furthermore, the Company has a 20-year purchase power agreement with Macho Springs Solar, LLC to purchase the entire generation output delivered from the 50 MW Macho Springs solar photovoltaic plant located in Luna County, New Mexico which began commercial operation in May 2014. Finally, the Company has a 30-year purchase power agreement with Newman Solar LLC to purchase the total output of approximately 10 MW from a solar photovoltaic plant on land subleased from the Company in proximity to its Newman Power Station. This solar photovoltaic plant began commercial operation in December 2014.

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EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

Environmental Matters

General. The Company is subject to extensive laws, regulations and permit requirements with respect to air and greenhouse gas ("GHG") emissions, water discharges, soil and water quality, waste management and disposal, natural resources and other environmental matters by federal, state, regional, tribal and local authorities. Failure to comply with such laws, regulations and requirements can result in actions by authorities or other third parties that might seek to impose on the Company administrative, civil and/or criminal penalties or other sanctions. In addition, releases of pollutants or contaminants into the environment can result in costly cleanup liabilities. These laws, regulations and requirements are subject to change through modification or reinterpretation, or the introduction of new laws and regulations and, as a result, the Company may face additional capital and operating costs to comply. Certain key environmental issues, laws and regulations facing the Company are described further below.

Air Emissions. The U.S. Clean Air Act ("CAA"), associated regulations and comparable state and local laws and regulations relating to air emissions impose, among other obligations, limitations on pollutants generated during the operations of the Company's facilities and assets, including sulfur dioxide ("SO2"), particulate matter ("PM"), nitrogen oxides ("NOx") and mercury.

Clean Air Interstate Rule/Cross State Air Pollution Rule. The EPA promulgated the Cross-State Air Pollution Rule ("CSAPR") in August 2011, which rule involves requirements to limit emissions of NOx and SO2 from certain of the Company's power plants in Texas and/or purchase allowances representing other parties' emissions reductions. CSAPR was intended to replace the EPA's 2005 Clean Air Interstate Rule ("CAIR"). While the U.S. Court of Appeals for the District of Columbia Circuit ("D.C. Circuit") vacated CSAPR in August 2012 and allowed CAIR to stand until the EPA issued a proper replacement, on April 29, 2014, the U.S. Supreme Court reversed and upheld CSAPR, remanding certain portions of CSAPR to the D.C. Circuit for further consideration. On June 26, 2014, the EPA filed a motion asking the D.C. Circuit to lift its stay on CSAPR, and on October 23, 2014, the D.C. Circuit lifted its stay of CSAPR. On July 28, 2015, the D.C. Circuit ruled that the EPA's emissions budgets for 13 states including Texas are invalid but left the rule in place on remand. On December 3, 2015, EPA published the proposed CSAPR Update Rule with a 60-day public comment period. While we are unable to determine the full impact of this decision until EPA takes further action, the Company believes it is currently positioned to comply with CSAPR.

National Ambient Air Quality Standards ("NAAQS"). Under the CAA, the EPA sets NAAQS for six criteria pollutants considered harmful to public health and the environment, including PM, NOx, carbon monoxide ("CO"), ozone and SO2. NAAQS must be reviewed by the EPA at five-year intervals. In 2010, the EPA tightened the NAAQS for both nitrogen dioxide ("NO2") and SO2. The EPA is considering a 1-hour secondary NAAQS for NO2 and SO2. In January 2013, the EPA tightened the NAAQS for fine PM. On October 1, 2015, following on its November 2014 proposal, EPA released a final rule tightening the primary and secondary NAAQS for ground-level ozone from its 2008 standard levels of 75 parts per billion ("ppb") to 70 ppb. Ozone is the main component of smog. While not directly emitted into the air, it forms from precursors, including NOx and volatile organic compounds, in combination with sunlight. The EPA is expected to make attainment/nonattainment designations for the revised ozone standards by October 1, 2017. While it is currently unknown how the areas in which we operate will be designated, for nonattainment areas classified as "Moderate" and above, states, and any tribes that choose to do so, are expected to be required to complete development of implementation plans in the 2020-2021 timeframe. Most nonattainment areas are expected to have until 2020 or 2023 to meet the primary (health) standard, with the exact attainment date varying based on the ozone level in the area. The Company continues to evaluate what impact these final and proposed NAAQS could have on its operations. If the Company is required to install additional equipment to control emissions at its facilities, the NAAQS, individually or in the aggregate, could have a material impact on its operations and financial results.

Mercury and Air Toxics Standards. The operation of coal-fired power plants, such as Four Corners, results in emissions of mercury and other air toxics. In December 2011, the EPA finalized Mercury and Air Toxics Standards (known as the "MATS Rule") for oil-and coal-fired power plants, which requires significant reductions in emissions of mercury and other air toxics. Several judicial and other challenges have been made to this rule, and on June 29, 2015, the U.S. Supreme Court remanded the rule to the D.C. Circuit Court. On December 15, 2015, the D.C. Circuit Court issued an order remanding the rule to EPA but did not vacate the rule during remand. EPA expects to issue a revised “appropriate and necessary” finding by April 15, 2016. The legal status of the MATS Rule notwithstanding, the Four Corners plant operator, APS, believes Units 4 and 5 will require no additional modifications to achieve compliance with the MATS Rule, as currently written. We cannot currently predict, however, what additional modifications or costs may be incurred if the EPA rewrites the MATS Rule on remand.

Other Laws and Regulations and Risks. The Company has entered into an agreement to sell its interest in Four Corners to APS at the expiration of the 50-year participation agreement in 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, which is subject to extensive regulation and litigation. By ceasing its participation in Four Corners, the Company expects to avoid the significant cost required to install

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NOTES TO FINANCIAL STATEMENTS

expensive pollution control equipment in order to continue operation of the plant as well as the risks of water availability that might adversely affect the amount of power available, or the price thereof, from Four Corners in the future. The closing of the transaction is subject to the receipt of regulatory approvals (see Part II, Item 8, Financial Statements and Supplementary Data, Note C).

Coal Combustion Waste. On October 19, 2015 the EPA's final rule regulating the disposal of coal combustion residuals (the "CCR Rule") from electric utilities as solid waste took effect. The Company has a 7% ownership interest in Units 4 and 5 of Four Corners, the only coal-fired generating facility for which the Company has an ownership interest subject to the CCR Rule. The Company entered into a Purchase and Sale Agreement with APS in February 2015 to sell the Company’s entire ownership interest in Four Corners. The CCR Rule requires plant owners to treat coal combustion residuals as Subtitle D (as opposed to a more costly Subtitle C) waste. In general, the Company is liable for only 7% of costs to comply with the CCR Rule (consistent with our ownership percentage). The Company, however, believes under the terms of the Purchase Agreement and after the pending sale, as a former owner, that the Company is not responsible for a significant portion of the costs under the CCR Rule, such as ongoing operational costs after July 2016. Accordingly, the Company does not expect the CCR Rule to have a significant impact on our financial condition or results of operations.

On November 3, 2015, the EPA published a final rule revising wastewater effluent limitation guidelines for steam electric power generators (the "Revised ELG Rule"). The Revised ELG Rule establishes requirements for wastewater streams from certain processes at affected facilities, including limits on toxic metals in wastewater discharges. Facilities must comply with the Revised ELG Rule between 2018 and 2023. The EPA anticipates that the new requirements in the Revised ELG Rule will only affect certain coal-fired steam electric power plants. Because the Company is not expected to have an interest in Four Corners after July 2016, the Company does not expect the Revised ELG Rule will have a significant impact on our financial condition or results of operations.

In 2012, several environmental groups filed a lawsuit in federal district court against the Office of Surface Mining Reclamation and Enforcement ("OSM") of the U.S. Department of the Interior challenging OSM’s 2012 approval of a permit revision which allowed for the expansion of mining operations into a new area of the mine that serves Four Corners ("Area IV North"). In April 2015, the court issued an order invalidating the permit revision, thereby prohibiting mining in Area IV North until OSM takes action to cure the defect in its permitting process identified by the court. On December 29, 2015, OSM took action to cure the defect in its permitting process by issuing a revised environmental assessment and finding of no new significant impact, and reissued the permit. This action is subject to possible judicial review.

Climate Change. In recent years, there has been increasing public debate regarding the potential impact on global climate change. There has been a wide-ranging policy debate, both nationally and internationally, regarding the impact of GHG and possible means for their regulation. In addition, efforts have been made and continue to be made in the international community toward the adoption of international treaties or protocols that would address global climate change issues. Most recently, in 2015, the United States participated in the United Nations Conference on Climate Change, which led to creation of the Paris Agreement. The Paris Agreement will be open for signing on April 22, 2016 and will require countries to review and "represent a progression" in their intended nationally determined contributions, which set GHG emission reduction goals, every five years beginning in 2020.

The U.S. federal government has either considered, proposed and/or finalized legislation or regulations limiting GHG emissions, including carbon dioxide. In particular, the U.S. Congress has considered legislation to restrict or regulate GHG emissions. In the past few years, the EPA began using the CAA to regulate carbon dioxide and other GHG emissions, such as the 2009 GHG Reporting Rule and the EPA’s sulfur hexafluoride ("SF6") reporting rule, both of which apply to the Company, as well as the EPA’s 2010 actions to impose permitting requirements on new and modified sources of GHG emissions. After announcing his plan to address climate change in 2013, the President directed the EPA to issue proposals for GHG rulemaking addressing power plants. In October 2015, the EPA published a final rule establishing new source performance standards ("NSPS") limiting CO2 emissions from new, modified and reconstructed electric generating units. In October 2015, the EPA also published a rule establishing guidelines for states to regulate CO2 emissions from existing power plants, as well as a proposed "federal plan" to address CO2 emissions from affected units in those states that do not submit an approvable compliance plan. The standards for existing plants are known as the Clean Power Plan ("CPP"), under which rule interim emissions performance rates must be achieved beginning in 2022 and final emissions performance rates by 2030. Legal challenges to the CPP have been filed by groups of states and industry members. On February 9, 2016, the U.S. Supreme Court issued a decision to stay the rule until legal issues are resolved. We cannot at this time determine the impact of the CPP and related rules and legal challenges may have on our financial position, results of operations or cash flows.

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NOTES TO FINANCIAL STATEMENTS

While a significant portion of the Company's generation assets are nuclear or gas-fired, and as a result, the Company believes that its GHG emissions are low relative to electric power companies who rely more on coal-fired generation, current and future legislation and regulation of GHG or any future related litigation could impose significant costs and/or operating restrictions on the Company, reduced demand for the power the Company generates and/or require the Company to purchase rights to emit GHG, any of which could be material to the Company's business, 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 November 2014, 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. On June 24, 2015, the parties filed with the U.S. District Court for New Mexico a settlement agreement ("CAA Settlement Agreement") resolving this matter. On August 17, 2015, the U.S. District Court for New Mexico entered the CAA Settlement Agreement. The agreement imposes a total civil penalty payable by the co-owners of Four Corners collectively in the amount of $1.5 million, and it requires the co-owners to pay $6.7 million for environmental mitigation projects. At December 31, 2015, the Company has accrued for its share of approximately $0.5 million related to this matter.

In a related action, on October 4, 2011, Earthjustice filed a lawsuit in the United States District Court for New Mexico alleging violations of the Prevention of Significant Deterioration ("PSD") provisions of the CAA related to Four Corners. Thereafter, on January 6, 2012, Earthjustice filed a First Amended Complaint adding claims for violations of the CAA's NSPS program. The lawsuit addressed allegations similar to those raised in the DOJ pre-enforcement action described in the preceding paragraph. Because the allegations in the DOJ pre-enforcement action and this lawsuit were substantially similar, the negotiations between the DOJ and APS regarding the pre-enforcement action also included Earthjustice. Accordingly, in response to the CAA Settlement Agreement, the parties to the case moved to dismiss the proceedings. Accordingly, the proceedings were terminated as of August 17, 2015. The CAA Settlement Agreement represents the final judgment in this case.

New Mexico Tax Matter Related to Coal Supplied to Four Corners

On May 23, 2013, the New Mexico Taxation and Revenue Department ("NMTRD") issued a notice of assessment for coal severance surtax, penalty, and interest totaling approximately $30 million related to coal supplied under the coal supply agreement for Four Corners (the "Assessment"). The Company's share of the assessment was approximately $1.5 million. On behalf of the Four Corners participants, the coal supplier made a partial payment of the Assessment and immediately filed a refund claim with respect to that partial payment in August 2013. The NMTRD denied the refund claim. On December 19, 2013, the coal supplier and APS, on its own behalf and as operating agent for Four Corners, filed complaints with the New Mexico District Court contesting both the validity of the Assessment and the refund claim denial. On June 30, 2015, the court ruled that the Assessment was not valid and further ruled that APS and the other Four Corners participants receive a refund of all the contested amounts previously paid under the applicable tax statue. The NMTRD filed a Notice of Appeal on August 31, 2015 with respect to the decision. The parties are engaged in settlement discussions and the Company does not expect the outcome to have a material impact on the Company's financial position, results of operations or cash flows.

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EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

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 leased certain warehouse facilities in El Paso under a lease which expired in December 2015. The Company also has several other leases for office, parking facilities and equipment which expire within the next five years. The Company has transmission and distribution lines which are operated under various property easement agreements. The majority of these easements include renewal options which the Company routinely exercises. These lease agreements do not impose any restrictions relating to issuance of additional debt, payment of dividends or entering into other lease arrangements. The Company has no significant capital lease agreements.

The Company's total annual rental expense related to operating leases was $1.9 million, $1.8 million, and $1.2 million for 2015, 2014 and 2013, respectively. As of December 31, 2015, the Company’s minimum future rental payments for the next five years are as follows (in thousands):



2016	$	900
2017	648
2018	538
2019	541
2020	548

L. Litigation

See Part II, Item 8, Financial Statements and Supplementary Data, Note C and Note K for discussion of the effects of government legislation and regulation on the Company as well as certain pending legal proceedings.

Table of Contents

EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

M. Employee Benefits

Retirement Plans

The Company’s Retirement Income Plan (the "Retirement Plan") is a qualified noncontributory defined benefit plan. Upon retirement or death of a vested plan participant, assets of the Retirement Plan are used to pay benefit obligations under the Retirement Plan. Contributions from the Company are at least the minimum funding amounts required by the IRS, as actuarially calculated. The assets of the Retirement Plan are primarily invested in common collective trusts which hold equity securities, debt securities and cash equivalents and are managed by a professional investment manager appointed by the Company.

The Company has two non-qualified retirement plans that are non-funded defined benefit plans. The Company's Supplemental Retirement Plan covers certain former employees and directors of the Company. The Excess Benefit Plan, was adopted in 2004 and covers certain active and former employees of the Company. The benefit cost for the non-qualified retirement plans are based on substantially the same actuarial methods and economic assumptions as those used for the Retirement Plan.

During the quarter ended March 31, 2014, the Company implemented certain amendments to the Retirement Plan and Excess Benefit Plan. In the first quarter of 2014, the Company offered a cash balance pension plan as an alternative to its current final average pay pension plan for employees hired prior to January 1, 2014. The cash balance pension plan also included an enhanced employer matching contribution to the employee’s respective 401(k) Defined Contribution Plan (discussed below). For employees that elected the new cash balance feature of the plans, the pension benefit earned under the existing final average pay feature of the plans was frozen as of March 31, 2014. Employees hired after January 1, 2014 were automatically enrolled in the cash balance pension plan. The amendments to the plans were effective April 1, 2014. As a result of these actions, the Company remeasured the assets and liabilities of the plans, based on actuarially determined estimates, using the close of the alternative choice election period of February 28, 2014, as the remeasurement date.

Prior to December 31, 2013, employees who completed one year of service with the Company and worked at least a minimum number of hours each year were covered by the final average pay formula of the plan. For participants that continue to be covered by the final average pay formula, retirement benefits are based on the employee’s final average pay and years of service. The cash balance pension plan covers employees beginning on their employment commencement date or re-employment commencement date in any plan year in which the employee completes at least a minimum number of hours of service. Retirement benefits under the cash balance pension plan are based on the employee’s cash balance account, consisting of pay credits and interest credits.

The Company complies with the FASB guidance on disclosure for pension and other post-retirement plans that requires disclosure of investment policies and strategies, categories of investment and fair value measurements of plan assets, and significant concentrations of risk.

Table of Contents

EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

The obligations and funded status of the plans are presented below (in thousands):



	December 31,
	2015						2014
	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	$	341,133		$	28,397		$	317,815		$	25,898
Service cost	8,530			262			8,284			303
Interest cost	13,477			1,018			14,001			1,041
Amendments (a)	—			—			(33,700		)	(500		)
Actuarial (gain) loss	(19,290		)	(810		)	50,741			3,508
Benefits paid	(18,144		)	(1,909		)	(16,008		)	(1,853		)
Benefit obligation at end of year	325,706			26,958			341,133			28,397
Change in plan assets:
Fair value of plan assets at end of prior year	272,939			—			257,831			—
Actual return (loss) on plan assets	(3,760		)	—			22,116			—
Employer contribution	9,000			1,909			9,000			1,853
Benefits paid	(18,144		)	(1,909		)	(16,008		)	(1,853		)
Fair value of plan assets at end of year	260,035			—			272,939			—
Funded status at end of year	$	(65,671	)	$	(26,958	)	$	(68,194	)	$	(28,397	)

_____________________

(a)Amendments relate to the modification of the Company’s Retirement Plan and Excess Benefit Plan discussed above.

Amounts recognized in the Company's balance sheets consist of the following (in thousands):



	December 31,
	2015						2014
	Retirement Income Plan			Non-Qualified Retirement Plans			Retirement Income Plan			Non-Qualified Retirement Plans
Current liabilities	$	—		$	(2,102	)	$	—		$	(2,319	)
Noncurrent liabilities	(65,671		)	(24,856		)	(68,194		)	(26,078		)
Total	$	(65,671	)	$	(26,958	)	$	(68,194	)	$	(28,397	)

The accumulated benefit obligation in excess of plan assets is as follows (in thousands):



	December 31,
	2015						2014
	Retirement Income Plan			Non-Qualified Retirement Plans			Retirement Income Plan			Non-Qualified Retirement Plans
Projected benefit obligation	$	(325,706	)	$	(26,958	)	$	(341,133	)	$	(28,397	)
Accumulated benefit obligation	(302,446		)	(25,785		)	(312,762		)	(27,603		)
Fair value of plan assets	260,035			—			272,939			—

Table of Contents

EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

Amounts recognized in accumulated other comprehensive income consist of the following (in thousands):



	Years Ended December 31,
	2015						2014
	Retirement Income Plan			Non-Qualified Retirement Plans			Retirement Income Plan			Non-Qualified Retirement Plans
Net loss	$	118,963		$	9,592		$	124,407		$	11,341
Prior service benefit	(27,344		)	(224		)	(30,811		)	(264		)
Total	$	91,619		$	9,368		$	93,596		$	11,077

The following are the weighted-average actuarial assumptions used to determine the benefit obligations:



	December 31,
	2015						2014
			Non-Qualified						Non-Qualified
	Retirement Income Plan		Supplemental Retirement Plan		Excess Benefit Plan		Retirement Income Plan		Supplemental Retirement Plan		Excess Benefit Plan
Discount rate	4.57	%	3.99	%	4.59	%	4.0	%	3.4	%	4.1	%
Rate of compensation increase	4.5	%	N/A		4.5	%	4.5	%	N/A		4.5	%

The Company reassesses various actuarial assumptions at least on an annual basis. The discount rate is reviewed at each measurement date. For 2015, the discount rate used to measure the fiscal year end obligation is based on a segmented spot rate yield curve that matches projected future payments with the appropriate interest rate applicable to the timing of the projected future benefit payments. A 1% increase in the discount rate would decrease the December 31, 2015 retirement plans' projected benefit obligation by 11.4%. A 1% decrease in the discount rate would increase the December 31, 2015 retirement plans' projected benefit obligation by 14%.

The components of net periodic benefit cost are presented below (in thousands):



	Years Ended December 31,
	2015						2014						2013
	Retirement Income Plan			Non-Qualified Retirement Plans			Retirement Income Plan			Non-Qualified Retirement Plans			Retirement Income Plan			Non-Qualified Retirement Plans
Service cost	$	8,530		$	262		$	8,284		$	303		$	9,137		$	190
Interest cost	13,477			1,018			14,001			1,041			12,742			872
Expected return on plan assets	(19,795		)	—			(18,699		)	—			(17,108		)	—
Amortization of:
Net loss	9,710			937			8,178			675			10,437			661
Prior service cost (benefit)	(3,467		)	(39		)	(2,889		)	(17		)	3			94
Net periodic benefit cost	$	8,455		$	2,178		$	8,875		$	2,002		$	15,211		$	1,817

In fiscal 2016, the Company expects to change the method used to estimate the service and interest components of net periodic benefit cost for pension benefits. This change compared to the previous method will result in a decrease in the service and interest components in future periods. Historically, the Company estimated service and interest costs utilizing a single weighted-average discount rate derived from the yield curve used to measure the benefit obligation at the beginning of the period. For fiscal 2016, the Company has elected to utilize a full yield curve approach to estimate these components by applying the specific spot rates along the yield curve used in the determination of the benefit obligation to the relevant projected cash flows. The Company believes the new approach provides a more precise measurement of service and interest costs by aligning the timing of the plan’s liability cash flows to the corresponding spot rates on the yield curve. The Company will account for this change as a change in accounting estimate and accordingly will account for this prospectively. The change in estimate is anticipated to decrease the service and interest components of net periodic benefit cost starting in 2016 by $2.9 million.

Table of Contents

EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

The changes in benefit obligations recognized in other comprehensive income are presented below (in thousands):



	Years Ended December 31,
	2015						2014						2013
	Retirement Income Plan			Non-Qualified Retirement Plans			Retirement Income Plan			Non-Qualified Retirement Plans			Retirement Income Plan			Non-Qualified Retirement Plans
Net (gain) loss	$	4,266		$	(811	)	$	47,324		$	3,508		$	(30,065	)	$	(533	)
Prior service benefit	—			—			(33,700		)	(500		)	—			—
Amortization of:
Net loss	(9,710		)	(937		)	(8,178		)	(675		)	(10,437		)	(661		)
Prior service (cost) benefit	3,467			39			2,889			17			(3		)	(94		)
Total recognized in other comprehensive income	$	(1,977	)	$	(1,709	)	$	8,335		$	2,350		$	(40,505	)	$	(1,288	)

The total amount recognized in net periodic benefit costs and other comprehensive income are presented below (in thousands):



	Years Ended December 31,
	2015				2014				2013
	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	$	6,478	$	469	$	17,210	$	4,352	$	(25,294	)	$	529

The following are amounts in accumulated other comprehensive income that are expected to be recognized as components of net periodic benefit cost during 2016 (in thousands):



	Retirement Income Plan			Non-Qualified Retirement Plans
Net loss	$	6,830		$	715
Prior service benefit	(3,470		)	(40		)

The following are the weighted-average actuarial assumptions used to determine the net periodic benefit cost for the twelve months ended December 31:



	2015						2014 (a)						2013
			Non-Qualified						Non-Qualified						Non-Qualified
	Retirement Income Plan		Supplemental Retirement Plan		Excess Benefit Plan		Retirement Income Plan		Supplemental Retirement Plan		Excess Benefit Plan		Retirement Income Plan		Supplemental Retirement Plan		Excess Benefit Plan
Discount rate	4.0	%	3.4	%	4.1	%	4.9	%	3.9	%	4.9	%	4.0	%	3.1	%	4.0	%
Expected long-term return on plan assets	7.5	%	N/A		N/A		7.5	%	N/A		N/A		7.5	%	N/A		N/A
Rate of compensation increase	4.5	%	N/A		4.5	%	4.75	%	N/A		4.75	%	4.75	%	N/A		4.75	%

_____________________


(a)	The Retirement Plan and the Excess Benefit Plan were remeasured on February 28, 2014 due to the above mentioned plan amendment. The discount rate used to remeasure the benefit obligation was 4.6% for the Retirement Plan and 4.5% for the Excess Benefit Plan, compared to 4.9% for both plans as of January 1, 2014. All other assumptions remained consistent with assumptions used at January 1, 2014.

Table of Contents

EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

The Company’s overall expected long-term rate of return on assets is 7.5% effective January 1, 2015, and 7.0% effective January 1, 2016, 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:



	December 31, 2015
Equity securities	50	%
Fixed income	40	%
Alternative investments	10	%
Total	100	%

The Retirement Plan invests the majority of its plan assets in common collective trusts which includes a diversified portfolio of domestic and international equity securities and fixed income securities. Alternative investments of the Retirement Plan are comprised of a real estate limited partnership and equity securities of real estate companies. The expected rate of returns for the funds are assessed annually and are based on long-term relationships among major asset classes and the level of incremental returns that can be earned by the successful implementation of different active investment management strategies. Equity and real estate equity returns are based on estimates of long-term inflation rate, real rate of return, 10-year Treasury bond premium over cash, an expected equity risk premium, as well as other economic factors. Fixed income returns are based on maturity, long-term inflation, real rate of return and credit spreads. These assumptions also capture the expected correlation of returns between these asset classes over the long term.

The FASB guidance on disclosure for pension plans requires disclosure of fair value measurements of plan assets. To increase consistency and comparability in fair value measurements, the FASB guidance on fair value measurements established a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value into three levels as follows:


•	Level 1 – Observable inputs that reflect quoted market prices for identical assets and liabilities in active markets. Prices of securities held in the mutual funds and underlying portfolios of the Retirement Plan are primarily obtained from independent pricing services. These prices are based on observable market data.


•	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 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.

Table of Contents

EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

The fair value of the Company’s Retirement Plan assets at December 31, 2015 and 2014, and the level within the three levels of the fair value hierarchy defined by the FASB guidance on fair value measurements are presented in the table below (in thousands):



Description of Securities	Fair Value as of December 31, 2015		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Cash and Cash Equivalents	$	1,266	$	1,266	$	—	$	—
Common Collective Trusts (a)
Equity funds	144,279		—		144,279		—
Fixed income funds	103,877		—		103,877		—
Real Estate Funds	2,025		—		2,025		—
Total Common Collective Trusts	250,181		—		250,181		—
Limited Partnership Interest in Real Estate (b)	8,588		—		—		8,588
Total Plan Investments	$	260,035	$	1,266	$	250,181	$	8,588



Description of Securities	Fair Value as of December 31, 2014		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Cash and Cash Equivalents	$	1,237	$	1,237	$	—	$	—
Common Collective Trust (a)
Equity funds	149,839		—		149,839		—
Fixed income funds	113,115		—		113,115		—
Total Common Collective Trusts	262,954		—		262,954		—
Limited Partnership Interest in Real Estate (b)	8,748		—		—		8,748
Total Plan Investments	$	272,939	$	1,237	$	262,954	$	8,748

_____________________


(a)	The Common Collective Trusts are invested in equity and 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 the real estate limited partnership during the period (in thousands):



	Fair Value of Investments in Real Estate
Balances at December 31, 2013	$	8,857
Sale of land	(357		)
Unrealized gain in fair value	248
Balances at December 31, 2014	8,748
Unrealized loss in fair value	(160		)
Balances at December 31, 2015	$	8,588

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, 2015 and 2014. Except as noted in the above table, there were no purchases, issuances, and settlements related to the assets in the Level 3 fair value measurement category during the twelve month periods ending December 31, 2015 and 2014.

Table of Contents

EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

The Company adheres to the traditional capital market pricing theory which maintains that over the long term, the risk of owning equities should be rewarded with a greater return than available from fixed income investments. The Company seeks to minimize the risk of owning equity securities by investing in funds that pursue risk minimization strategies and by diversifying its investments to limit its risks during falling markets. The investment manager has full discretionary authority to direct the investment of plan assets held in trust within the guidelines prescribed by the Company through the plan’s investment policy statement including the ability to hold cash equivalents. The investment guidelines of the investment policy statement are in accordance with the Employee Retirement Income Security Act of 1974 ("ERISA") and Department of Labor ("DOL") regulations.

The Company contributes at least the minimum funding amounts required by the IRS for the Retirement Plan, as actuarially calculated. The Company expects to contribute at least $6.2 million to its retirement plans in 2016.

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
2016	$	12,502	$	2,102
2017	13,752		2,069
2018	14,973		2,059
2019	16,141		2,024
2020	17,210		1,985
2021-2025	100,358		9,151

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 2015, 2014 and 2013 were $3.9 million, $3.0 million, and $1.9 million, respectively. Historically, the Company had provided a 50 percent matching contribution up to 6 percent of the employee’s compensation subject to certain other limits and exclusions. Effective April 1, 2014, for employees who enrolled in the cash balance pension plan (discussed above), the Company provided a 100 percent matching contribution up to 6 percent of the employee's compensation subject to certain other limits and exclusions.


(a)	Amendment relates to modification of the Company's Other Post-retirement Benefit Plan which increased mail order co-payments for post age 65 medications. The plan change was approved in 2015. The amendment became effective January 1, 2016.



	2015		2014		2013 (a)
Discount rate at beginning of year	4.1	%	4.9	%	4.1	%
Expected long-term return on plan assets	5.2	%	5.2	%	5.2	%
Health care cost trend rates:
Initial	7.25	%	7.5	%	7.75	%
Ultimate	4.5	%	4.5	%	4.5	%
Year ultimate reached	2026		2026		2026


(a)	The institutional funds 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.



	Fair Value of Investments in Real Estate
Balance at December 31, 2013	$	1,661
Sale of land	(67		)
Unrealized gain in fair value	46
Balance at December 31, 2014	1,640
Unrealized gain in fair value	(30		)
Balance at December 31, 2015	$	1,610



2016	$	3,426
2017	3,814
2018	4,178
2019	4,449
2020	4,807
2021-2025	27,761



	December 31, 2015
	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	$	9,383	$	(97	)	$	1,113	$	(47	)	$	10,496	$	(144	)
U.S. Government Bonds	24,094		(310		)	14,272		(623		)	38,366		(933		)
Municipal Obligations	8,286		(160		)	7,388		(446		)	15,674		(606		)
Corporate Obligations	6,058		(722		)	2,307		(228		)	8,365		(950		)
Total Debt Securities	47,821		(1,289		)	25,080		(1,344		)	72,901		(2,633		)
Common Stock	3,584		(344		)	—		—			3,584		(344		)
Institutional Funds-International Equity	22,454		(768		)	—		—			22,454		(768		)
Total Temporarily Impaired Securities	$	73,859	$	(2,401	)	$	25,080	$	(1,344	)	$	98,939	$	(3,745	)



	Total		2016		2017 through 2020		2021 through 2025		2026 and Beyond
Municipal Debt Obligations	$	24,345	$	723	$	9,196	$	11,524	$	2,902
Corporate Debt Obligations	18,475		352		6,757		5,983		5,383
U.S. Government Bonds	50,399		3,418		21,970		13,719		11,292


•	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 3 - Unobservable inputs using data that is not corroborated by market data and primarily based on internal Company analysis using models and various other analysis. Financial assets utilizing Level 3 inputs include the Company's investments in debt securities.



	2015 Quarters								2014 Quarters
	4th		3rd		2nd		1st		4th		3rd		2nd		1st
					(In thousands except for share data)
Operating revenues (1)	$	176,902	$	289,713	$	219,508	$	163,746	$	196,563	$	283,645	$	251,801	$	185,516
Operating income	8,312		88,047		41,872		7,960		8,871		81,496		51,131		9,665
Net income	648		56,740		21,072		3,458		4,241		52,476		30,096		4,615
Basic earnings per share:
Net income	0.02		1.40		0.52		0.09		0.10		1.30		0.75		0.11
Diluted earnings per share:
Net income	0.02		1.40		0.52		0.09		0.10		1.30		0.75		0.11
Dividends declared per share of common stock	0.295		0.295		0.295		0.280		0.280		0.280		0.280		0.265


(1)	Operating revenues are seasonal in nature, with the peak sales periods generally occurring during the summer months. Comparisons among quarters of a year may not represent overall trends and changes in operations.


Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure


Item 10.	Directors, Executive Officers of the Registrant and Corporate Governance



Name	Age	Current Position and Business Experience
Mary E. Kipp	48	Chief Executive Officer since December 2015; President from September 2014 to December 2015; Senior Vice President, General Counsel and Chief Compliance Officer from June 2010 to September 2014.
Nathan T. Hirschi	52	Senior Vice President and Chief Financial Officer since October 2013; Vice President and Controller from March 2010 to October 2013.
Steven T. Buraczyk	48	Senior Vice President of 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 of System Operations and Planning from January 2011 to August 2012.
Rocky R. Miracle	63	Senior Vice President of Corporate Services and Chief Compliance Officer since December 2015; Senior Vice President of Corporate Planning & Development and Chief Compliance Officer from September 2014 to December 2015; Senior Vice President of Corporate Planning and Development from August 2009 to September 2014.
William A. Stiller	64	Senior Vice President of Public & Customer Affairs and Chief Human Resources Officer since December 2015; Senior Vice President of Human Resources and Customer Care from October 2013 to December 2015; Vice President and Chief Human Resources Officer from January 2013 to October 2013; Independent Human Resources consultant from 2005 to 2013.
John R. Boomer	54	Senior Vice President and General Counsel since December 2015; Vice President and General Counsel from September 2014 to December 2015; Vice President and Treasurer from April 2014 to September 2014; Senior Vice President for Helen of Troy Limited from February 2012 to January 2014; Senior Vice President-International for Helen of Troy Limited from July 2008 to February 2012.
Russell G. Gibson	63	Vice President and Controller since September 2014; Chief Financial Officer and Vice President for ReadyOne Industries, Inc. from June 2006 to September 2014.



Plan Category	Number of securities to be issued upon exercise of outstanding options, warrants and rights (a)	Weighted-average exercise price of outstanding options, warrants and rights (b)		Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) (c)
Equity compensation plans
approved by security holders	—	$	—	1,499,757
Equity compensation plans
not approved by security holders	—	—		—
Total	—	$	—	1,499,757


Item 13.	Certain Relationships and Related Transactions, and Director Independence



		Page
1.	Financial Statements:

	See Index to Financial Statements	46

2.	Financial Statement Schedules:

	All schedules are omitted as the required information is not applicable or is included in the financial statements or related notes thereto.

3.	Exhibits



Exhibit Number			Title
Exhibit 3 –		Articles of Incorporation and Bylaws:
	3.01	–	Restated Articles of Incorporation of the Company, dated February 7, 1996 and effective February 12, 1996. (Exhibit 3.01 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1995)
	3.02	–	Bylaws of the Company, dated February 6, 1996. (Exhibit 3.02 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1995)
Exhibit 4 –		Instruments Defining the Rights of Security Holders, including Indentures:
	4.01	–	General Mortgage Indenture and Deed of Trust, dated as of February 1, 1996, and First Supplemental Indenture, dated as of February 1, 1996, including form of Series A through H First Mortgage Bonds. (Exhibit 4.01 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1995)
4.01-01		–	Second Supplemental Indenture, dated as of August 19, 1997, to Exhibit 4.01. (Exhibit 4.01 to the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 1997)
4.01-02		–	Third Supplemental Indenture, dated as of January 29, 1999, to Exhibit 4.01. (Exhibit 4.3 to the Company’s Registration Statement on Form S-3, dated March 29, 2005)
4.01-03		–	Fourth Supplemental Indenture, dated as of January 25, 2002, to Exhibit 4.01. (Exhibit 4.4 to the Company’s Registration Statement on Form S-3, dated March 29, 2005)
4.01-04		–	Fifth Supplemental Indenture, dated as of December 17, 2004, to Exhibit 4.01. (Exhibit 4.01-02 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2004)
4.01-05		–	Sixth Supplemental Indenture to Exhibit 4.01, dated as of May 5, 2005 to General Mortgage Indenture and Deed of Trust dated as of February 1, 1996 between the Company and U.S. Bank National Association as trustee. (Exhibit 4.01 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2005)
4.01-06		–	Seventh Supplemental Indenture to Exhibit 4.01, dated as of April 11, 2006 to General Mortgage Indenture and Deed of Trust dated as of February 1, 1996 between the Company and U.S. Bank National Association as trustee. (Exhibit 4.01 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2015)
4.01-07		–	Eighth Supplemental Indenture to Exhibit 4.01, dated as of July 7, 2015 to General Mortgage Indenture and Deed of Trust dated as of February 1, 1996 between the Company and U.S. Bank National Association as trustee. (Exhibit 4.02 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2015)
	4.02	–	Bond Purchase Agreement dated March 19, 2009, among El Paso Electric Company, J.P. Morgan Securities, Inc., BNY Mellon Capital Markets, LLC, Maricopa County, Arizona Pollution Control Corporation, relating to the Pollution Control Bonds referred to in Exhibit 4.06 and 4.08. (Exhibit 4.05 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2009)
	4.03	–	Indenture of Trust between Maricopa County, Arizona Pollution Control Corporation and Union Bank of California, N.A. as Trustee dated as of August 1, 2012 relating to $59,235,000 Maricopa County, Arizona Pollution Control Corporation Pollution Control Refunding Revenue Bonds 2012 Series A (El Paso Electric Company Palo Verde Project). (Exhibit 4.05 to the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2012)
	4.04	–	Loan Agreement dated August 1, 2012 between Maricopa County, Arizona Pollution Control Corporation and El Paso Electric Company relating to the Pollution Control Bonds referred to in Exhibit 4.03. (Exhibit 4.06 to the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2012)
	4.05	–	Reserved
	4.06	–	Indenture of Trust between Maricopa County, Arizona Pollution Control Corporation and Union Bank, N.A. as Trustee dated as of March 1, 2009 relating to $63,500,000 Maricopa County, Arizona Pollution Control Corporation Pollution Control Refunding Revenue Bonds 2009 Series A (El Paso Electric Company Palo Verde Project). (Exhibit 4.01 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2009)
	4.07	–	Loan Agreement dated March 1, 2009 between Maricopa County, Arizona Pollution Control Corporation and El Paso Electric Company relating to the Pollution Control Bonds referred to in Exhibit 4.06. (Exhibit 4.02 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2009)
	4.08	–	Indenture of Trust between Maricopa County, Arizona Pollution Control Corporation and Union Bank, N.A. as Trustee dated as of March 1, 2009 relating to $37,100,000 Maricopa County, Arizona Pollution Control Corporation Pollution Control Refunding Revenue Bonds 2009 Series B (El Paso Electric Company Palo Verde Project). (Exhibit 4.03 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2009)



Exhibit Number			Title
	4.09	–	Loan Agreement dated March 1, 2009 between Maricopa County, Arizona Pollution Control Corporation and El Paso Electric Company relating to the Pollution Control Bonds referred to in Exhibit 4.08. (Exhibit 4.04 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2009)
	4.10	–	Remarketing and Purchase Agreement dated August 1, 2012 among El Paso Electric Company and U.S. Bancorp Investments, Inc. relating to the Pollution Control Bonds referred to in Exhibit 4.13. (Exhibit 4.02 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2012)
	4.11	–	Tender Agreement dated August 1, 2012 between El Paso Electric Company and Union Bank, N.A., relating to the Pollution Control Bonds referred to in Exhibit 4.13. (Exhibit 4.03 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2012)
	4.12	–	Amended and Restated Installment Sale Agreement, dated as of August 1, 2012, between El Paso Electric Company and the City of Farmington, New Mexico, relating to the Pollution Control Bonds referred to in Exhibit 4.13. (Exhibit 4.04 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2012)
	4.13	–	Ordinance No. 2012-1256 adopted by the City Council of Farmington, New Mexico on June 12, 2012 authorizing and providing for the issuance by the City of Farmington, New Mexico of $33,300,000 in aggregate principal amount of its Pollution Control Revenue Refunding Bonds, 2012 Series A (El Paso Electric Company Four Corners Project). (Exhibit 4.01 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2012)
	4.14	–	Debt Securities Indenture, dated as of May 1, 2005. (Exhibit 4.1 to the Company's Current Report on Form 8-K, dated May 17, 2005)
	4.15	–	First Supplemental Indenture, dated as of May 19, 2008. (Exhibit 4.4 to the Company's Registration Statement on Form S-3, dated May 20, 2008)
	4.16	–	Securities Resolution No. 1, dated May 11, 2005, relating to the Company's 6.00% Senior Notes due 2035. (Exhibit 4.2 to the Company's Current Report on Form 8-K dated May 17, 2005)
	4.17	–	Securities Resolution No. 2, dated May 29, 2008, relating to the Company's 7.50% Senior Notes due 2038. (Exhibit 4.2 to the Company's Current Report on Form 8-K dated June 3, 2008)
	4.18	–	Securities Resolution No. 3, dated December 3, 2012, relating to the Company's 3.30% Senior Notes due 2022. (Exhibit 4.01 to the Company's Current Report on Form 8-K dated December 6, 2012)
	4.19	–	Bond Purchase Agreement dated August 15, 2012, among Maricopa County, Arizona Pollution Control Corporation, U.S. Bancorp Investments, Inc., and Merrill Lynch, Pierce, Fenner & Smith Incorporated, relating to the Pollution Control Bonds referred to in Exhibit 4.03. (Exhibit 4.07 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2012)
	4.20	–	Securities Resolution No. 4, dated December 1, 2014, relating to the Company's 5.000% Senior Notes due 2044. (Exhibit 4. 1 to the Company's Current Report on Form 8-K dated December 1, 2014)
Exhibit 10 –		Material Contracts:
	10.01	–	Co-Tenancy Agreement, dated July 19, 1966, and Amendments No. 1 through 5 thereto, between the Participants of the Four Corners Project, defining the respective ownerships, rights and obligations of the Parties. (Exhibit 10.01 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1995)
10.01-01		–	Amendment No. 6, dated February 3, 2000, to Exhibit 10.01. (Exhibit 10.01-01 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2002)
10.01-02		–	Amendment No. 7, dated December 30, 2013, to Exhibit 10.01. (Exhibit 10.02 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2014)
10.01-03		–	Amendment No. 8, dated March 15, 2015, to Exhibit 10.01. (Exhibit 10.01 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2015)
	10.02	–	Supplemental and Additional Indenture of Lease, dated May 27, 1966, including amendments and supplements to original Lease Four Corners Units 1, 2 and 3, between the Navajo Tribe of Indians and Arizona Public Service Company, and including new Lease Four Corners Units 4 and 5, between the Navajo Tribe of Indians and Arizona Public Service Company, the Company, Public Service Company of New Mexico, Salt River Project Agricultural Improvement and Power District, Southern California Edison Company and Tucson Gas & Electric Company. (Exhibit 4-e to Registration Statement No. 2-28692 on Form S-9)
10.02-01		–	Amendment and Supplement No. 1, dated March 21, 1985, to Exhibit 10.02. (Exhibit 19.3 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 1985)
10.02-02		–	Amendment and Supplement No. 2, dated March 7, 2011, to Exhibit 10.02. (Exhibit 10.07 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2014)



Exhibit Number			Title
10.02-03		–	Amendment and Supplement No. 3, dated March 7, 2011, to Exhibit 10.02. (Exhibit 10.08 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2014)
10.03		–	Reserved
	10.04	–	Four Corners Project Operating Agreement, dated May 15, 1969, between Arizona Public Service Company, the Company, Public Service Company of New Mexico, Salt River Project Agricultural Improvement and Power District, Southern California Edison Company and Tucson Gas & Electric Company, and Amendments 1 through 10 thereto. (Exhibit 10.04 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1995)
10.04-01		–	Amendment No. 11, dated May 23, 1997, to Exhibit 10.04. (Exhibit 10.04-01 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 1997)
10.04-02		–	Amendment No. 12, dated February 3, 2000, to Exhibit 10.04. (Exhibit 10.04-02 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2002)
10.04-03		–	Amendment No. 13, dated December 1, 2010, to Exhibit 10.04. (Exhibit 10.03 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2014)
10.04-04		–	Amendment No. 14, dated December 30, 2013, to Exhibit 10.04. (Exhibit 10.04 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2014)
10.04-05		–	Amendment No. 15, dated March 15, 2015, to Exhibit 10.04. (Exhibit 10.02 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2015)
	10.05	–	Arizona Nuclear Power Project Participation Agreement, dated August 23, 1973, between Arizona Public Service Company, Public Service Company of New Mexico, Salt River Project Agricultural Improvement and Power District, Tucson Gas & Electric Company and the Company, describing the respective participation ownerships of the various utilities having undivided interests in the Arizona Nuclear Power Project and in general terms defining the respective ownerships, rights, obligations, major construction and operating arrangements of the Parties, and Amendments No. 1 through 13 thereto. (Exhibit 10.05 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1995)
10.05-01		–	Amendment No. 14, dated June 20, 2000, to Exhibit 10.05. (Exhibit 10.05-01 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2002)
10.05-02		–	Amendment No. 15, dated January 13, 2011, to Exhibit 10.05. (Exhibit 10.07 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2012)
10.05-03		–	Amendment No. 16, dated April 28, 2014, to Exhibit 10.05. (Exhibit 10.06 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2014)
	10.06	–	ANPP Valley Transmission System Participation Agreement, dated August 20, 1981, and Amendments No. 1 and 2 thereto. APS Contract No. 2253-419.00. (Exhibit 10.06 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1995)
	10.07	–	Arizona Nuclear Power Project High Voltage Switchyard Participation Agreement, dated August 20, 1981. APS Contract No. 2252-419.00. (Exhibit 20.14 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1981)
10.07-01		–	Amendment No. 1, dated November 20, 1986, to Exhibit 10.07. (Exhibit 10.11-01 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1986)
	10.08	–	Firm Palo Verde Nuclear Generating Station Transmission Service Agreement, between Salt River Project Agricultural Improvement and Power District and the Company, dated October 18, 1983. (Exhibit 19.12 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1983)
	10.09	–	Interconnection Agreement, as amended, dated December 8, 1981, between the Company and Southwestern Public Service Company, and Service Schedules A through F thereto. (Exhibit 10.13 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1995)
	10.10	–	Amrad to Artesia 345 KV Transmission System and DC Terminal Participation Agreement, dated December 8, 1981, between the Company and Texas-New Mexico Power Company, and the First through Third Supplemental Agreements thereto. (Exhibit 10.14 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1995)
#10.11		–	El Paso Electric Company Excess Benefit Plan, dated as of December 31, 2008. (Exhibit 10.04 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2009)
	10.12	–	Interconnection Agreement and Amendment No. 1, dated July 19, 1966, between the Company and Public Service Company of New Mexico. (Exhibit 19.01 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1982)



Exhibit Number			Title
	10.13	–	Southwest New Mexico Transmission Project Participation Agreement, dated April 11, 1977, between Public Service Company of New Mexico, Community Public Service Company and the Company, and Amendments 1 through 5 thereto. (Exhibit 10.16 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1995)
10.13-01		–	Amendment No. 6, dated as of June 17, 1999, to Exhibit 10.13. (Exhibit 10.09 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 1999)
	10.14	–	Tucson-El Paso Power Exchange and Transmission Agreement, dated April 19, 1982, between Tucson Electric Power Company and the Company. (Exhibit 19.26 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1982)
10.14-01		–	Settlement Agreement between TEP and the Company, dated April 26, 2011, to Exhibit 10.14. (Exhibit 10.14-01 to the Company's Annual Report on Form 10-K for the year ended December 31, 2011)
	10.15	–	Southwest Reserve Sharing Group Participation Agreement, dated January 1, 1998, between the Company, Arizona Electric Power Cooperative, Arizona Public Service Company, City of Farmington, Los Alamos County, Nevada Power Company, Plains Electric G&T Cooperative, Inc., Public Service Company of New Mexico, Tucson Electric Power and Western Area Power Administration. (Exhibit 10.18 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1997)
	10.16	–	Arizona Nuclear Power Project Transmission Project Westwing Switchyard Amended Interconnection Agreement, dated August 14, 1986, between The United States of America; Arizona Public Service Company; Department of Water and Power of the City of Los Angeles; Nevada Power Company; Public Service Company of New Mexico; Salt River Project Agricultural Improvement and Power District; Tucson Electric Power Company; and the Company. (Exhibit 10.72 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1986)
#10.17		–	Form of Indemnity Agreement, between the Company and its directors and officers. (Exhibit 10.17 to the Company's Annual Report on Form 10-K for the year ended December 31, 2012)
	10.18	–	Interchange Agreement, executed April 14, 1982, between Comisión Federal de Electricidad and the Company. (Exhibit 19.2 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 1991)
	10.19	–	Trust Agreement, dated as of February 12, 1996, between the Company and Texas Commerce Bank National Association, as Trustee of the Rio Grande Resources Trust II. (Exhibit 10.34 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1995)
	10.20	–	Purchase Contract, dated as of February 12, 1996, between the Company and Texas Commerce Bank National Association, as Trustee of the Rio Grande Resources Trust II. (Exhibit 10.35 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1995)
10.20-01		–	Second Amendment, dated as of July 12, 2007, to the Purchase Contract referred to in Exhibit 10.20 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2006. (Exhibit 10.09 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2007)
10.20-02		–	Third Amendment, dated as of August 17, 2010, to the Purchase Contract referred to in Exhibit 10.20 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2009. (Exhibit 10.05 to the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2010)
10.20-03		–	Fourth Amendment, dated as of September 23, 2010, to the Purchase Contract referred to in Exhibit 10.20 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2009. (Exhibit 10.06 to the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2010)
	10.21	–	Note Purchase Agreement, dated as of August 17, 2010, between El Paso Electric Company, Rio Grande Resources Trust II and the purchasers named therein. (Exhibit 10.1 to the Company’s Form 8-K, dated as of August 17, 2010)
	10.22	–	Decommissioning Trust Agreement, dated as of April 1, 2006, between the Company and Wells Fargo Bank, N.A., as decommissioning trustee for Palo Verde Unit 1. (Exhibit 10.02 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2006)
	10.23	–	Decommissioning Trust Agreement, dated as of April 1, 2006, between the Company and Wells Fargo Bank, N.A., as decommissioning trustee for Palo Verde Unit 2. (Exhibit 10.03 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2006)
	10.24	–	Decommissioning Trust Agreement, dated as of April 1, 2006, between the Company and Wells Fargo Bank, N.A., as decommissioning trustee for Palo Verde Unit 3. (Exhibit 10.04 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2006)



Exhibit Number			Title
	10.25	–	Credit agreement dated as of September 23, 2010, among the Company, The Bank of New York Mellon Trust Company, N.A., not in its individual capacity, but solely in its capacity as successor trustee of the Rio Grande Resources Trust II, the lenders party thereto, JPMorgan Chase Bank, N.A., as administrative agent and issuing bank and Union Bank, N.A., as syndication agent. (Exhibit 10.07 to the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2010)
10.25-01		–	Amended and Restated Credit Agreement dated as of November 15, 2011, among the Company, The Bank of New York Mellon Trust Company, N.A., not in its capacity, but solely in its capacity as successor trustee of the Rio Grande Resources Trust II, the lenders party thereto, JP Morgan Chase Bank, N.A., as administrative agent and issuing bank and Union Bank, N.A., as syndication agent.(Exhibit 10.25-01 to the Company's Annual Report on Form 10-K for the year ended December 31, 2011)
10.25-02		–	Incremental Facility Assumption Agreement dated as of March 29, 2012, related to the Amended and Restated Credit Agreement, referred to in Exhibit 10.25-01, among the Company and The Bank of New York Mellon Trust Company, N.A., not in its individual capacity, but solely in its capacity as successor trustee of the Rio Grande Resources Trust II, the lenders from time to time party thereto, JPMorgan Chase Bank, N.A., as issuing bank and as administrative agent and Union Bank, N.A., as syndication agent. (Exhibit 10.02 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2012)
10.25-03		–	Second Amended and Restated Credit agreement dated as of January 14, 2014, among the Company, The Bank of New York Mellon Trust Company, N.A., not in its individual capacity, but solely in its capacity as trustee of the Rio Grande Resources Trust II, the lenders party thereto, JPMorgan Chase Bank, N.A., as administrative agent and issuing bank and Union Bank of California, N.A., as syndication agent. (Exhibit 10.25-03 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2013)
#†10.26		–	Change in Control Agreement between the Company and certain key officers of the Company.
	10.27	–	Purchase and Sale Agreement between the Company and Arizona Public Service Company, dated February 17, 2015. (Exhibit 10.1 to Current Report on Form 8-K filed on February 19, 2015)
10.27-01		–	Amendment No. 1, dated April 13, 2015, to Exhibit 10.27. (Exhibit 10.03 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2015)
10.28		–	Reserved
#10.29		–	Form of Directors’ Restricted Stock Award Agreement between the Company and certain directors of the Company. (Exhibit 10.07 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 1999)
10.30		–	Reserved
10.31		–	Franchise Agreement, dated July 12, 2005, between the Company and the City of El Paso. (Exhibit 10.05 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2015)
10.31-01		–	Amendment No. 1, dated November 16, 2010, to Exhibit 10.31. (Exhibit 10.06 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2015)
	10.32	–	Settlement Agreement, dated as of February 24, 2000, with the City of Las Cruces. (Exhibit 10.01 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2000)
	10.33	–	Franchise Agreement, dated April 3, 2000, between the Company and the City of Las Cruces. (Exhibit 10.02 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2000)
#10.34		–	Employment Agreement for Hector Puente, dated April 23, 2001. (Exhibit 10.07 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2001)
	10.35	–	Shiprock – Four Corners Project 345 kV Switchyard Interconnection Agreement, dated March 6, 2002. APS Contract No. 51999. (Exhibit 10.06 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2002)
10.35-01		–	Amendment No. 1, dated December 30, 2013, to Exhibit 10.35. (Exhibit 10.05 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2014)
	10.36	–	Interconnection Agreement dated as of May 23, 2002, between the Company and the Public Service Company of New Mexico. (Exhibit 10.09 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2002)
10.36-01		–	First Amended and Restated Interconnection Agreement, dated October 9, 2003, to Exhibit 10.36. (Exhibit 10.52.01 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2003)
	10.37	–	Reserved
	10.38	–	Reserved
	10.39	–	Eight Treasury Rate Lock agreements between the Company and Credit Suisse First Boston International. (Exhibit 10.02 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2005)



Exhibit Number			Title
10.40		–	Reserved
	10.41	–	Reserved
	10.42	–	Power Purchase and Sale Agreement, dated as of December 16, 2005, between the Company and Phelps Dodge Energy Services, LLC. (Exhibit 10.42 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2005)
10.42-01		–	Letter Agreement, dated June 3, 2008, to Exhibit 10.42. (Exhibit 10.42-01 to the Company's Annual Report on Form 10-K for the year ended December 31, 2010)
10.42-02		–	Letter Agreement, dated November 26, 2008, to Exhibit 10.42. (Exhibit 10.42-02 to the Company's Annual Report on Form 10-K for the year ended December 31, 2010)
10.42-03		–	Letter Agreement, dated November 12, 2010, to Exhibit 10.42. (Exhibit 10.42-03 to the Company's Annual Report on Form 10-K for the year ended December 31, 2010)
10.42-04		–	Letter Agreement, dated April 29, 2011, to Exhibit 10.42. (Exhibit 10.04 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2011)
10.42-05		–	Letter Agreement, dated May 13, 2013, to Exhibit 10.42.
10.42-06		–	Letter Agreement, dated September 17, 2014, to Exhibit 10.42.
10.42-07		–	Letter Agreement, dated October 13, 2015, to Exhibit 10.42. (Exhibit 10.07 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2015)
	10.43	–	Settlement Agreement between the State of Texas and the Company, dated as of October 17, 2006. (Exhibit 10.08 to the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2006)
10.44		–	Reserved
10.45		–	Reserved
#10.46		–	El Paso Electric Company 2007 Long-Term Incentive Plan. (Exhibit 10.1 to the Company’s Form 8-K, dated as of May 2, 2007)
#10.46-01		–	Amended and Restated 2007 Long-Term Incentive Plan to Exhibit 10.46. (Exhibit 99.1 to the Registration Statement No. 333-196628 on Form S-8)
#10.47		–	Employment Agreement between the Company and Thomas V. Shockley, III, dated June 1, 2012. (Exhibit 10.05 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2012)
#10.47-01		–	Amendment to Employment Agreement between the Company and Thomas V. Shockley, III dated May 2, 2013. (Exhibit No. 1 to the Company's Form 8-K, dated May 2, 2013.)
#10.47-02		–	Amended and Restated Employment Agreement between the Company and Thomas V. Shockley, III, dated November 20, 2013. (Exhibit 10.47.02 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2013)
10.48		–	Employment Transition Agreement between the Company and David G. Carpenter, dated November 20, 2013. (Exhibit 10.48 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2013)
10.49		–	Employment Transition Agreement between the Company and Hector R. Puente, dated November 20, 2013. (Exhibit 10.49 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2013)
*#10.50		–	Employment Agreement between the Company and Mary E. Kipp, dated December 15, 2015.
Exhibit 12 –		Computation of Ratios:
*12.01 –			Computation of Ratios of Earnings to Fixed Charges
Exhibit 23 –		Consent of Experts:
*23.01		–	Consent of KPMG LLP (set forth on page 118 of this report)
Exhibit 24 –		Power of Attorney:
*24.01		–	Power of Attorney (set forth on page 116 of this report)
*24.02		–	Certified copy of resolution authorizing signatures pursuant to Power of Attorney
Exhibit 31 and 32 –		Certifications:



Exhibit Number			Title
*31.01		–	Certifications pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
*32.01		–	Certifications pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
Exhibit 99 –		Additional Exhibits:
	99.01	–	Agreed Order, entered August 30, 1995, by the Public Utility Commission of Texas. (Exhibit 99.31 to Registration Statement No. 33-99744 on Form S-1)
	99.02	–	Reserved
	99.03	–	Final Order, entered September 24, 1998, by the New Mexico Public Utility Commission. (Exhibit 99.31 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1998)
	99.04	–	Final Order, entered June 8, 1999, by the Public Utility Commission of Texas. (Exhibit 99.01 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 1999)
	99.05	–	Final Order, entered January 8, 2002, by the New Mexico Public Utility Commission. (Exhibit 99.05 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2002)
	99.06	–	News Release, dated as of December 5, 2002, by the El Paso Electric Company announcing settlement with the FERC Trial Staff. (Exhibit 99.01 to the Company’s Form 8-K, dated as of December 6, 2002)
	99.07	–	"Stipulated Facts and Remedies," dated as of December 5, 2002, to be filed by the FERC Trial Staff as part of its written testimony. (Exhibit 99.02 to the Company’s Form 8-K, dated as of December 6, 2002)
Exhibit 101 –		XBRL – Related Documents:
*101.INS		–	XBRL Instance Linkbase Document
*101.SCH		–	XBRL Taxonomy Extension Schema Linkbase Document
*101.CAL		–	XBRL Taxonomy Extension Calculation Linkbase Document
*101.DEF		–	XBRL Taxonomy Extension Definition Linkbase Document
*101.LAB		–	XBRL Taxonomy Extension Label Linkbase Document
*101.PRE		–	XBRL Taxonomy Extension Presentation Linkbase Document



	*		Filed herewith.
	#		Management contracts or compensatory plans or arrangements required to be identified by Item 15(a)(3) of Form 10-K.
	†		Agreements substantially identical in all material respects to this exhibit have been entered into between the Company and its Section 16 officers.
	††		Confidential treatment has been requested and received for the redacted portions of these Exhibits. The copies filed omit the information subject to the confidentiality request. Omissions are designated as "****." A complete version of these Exhibits has been filed separately with the Securities and Exchange Commission.



EL PASO ELECTRIC COMPANY

By:	/s/ MARY E. KIPP
	Mary E. Kipp
	Chief Executive Officer (Principal Executive Officer)



Signature	Title	Date

/s/ MARY E. KIPP	Chief Executive Officer and Director (Principal Executive Officer)	February 29, 2016
(Mary E. Kipp)

/s/ NATHAN T. HIRSCHI	Senior Vice President and Chief Financial Officer (Principal Financial Officer)	February 29, 2016
(Nathan T. Hirschi)

/s/ RUSSELL G. GIBSON	Vice President and Controller (Principal Accounting Officer)	February 29, 2016
(Russell G. Gibson)

/s/ CATHERINE A. ALLEN	Director	February 29, 2016
(Catherine A. Allen)

/s/ JOHN ROBERT BROWN	Director	February 29, 2016
(John Robert Brown)

/s/ JAMES W. CICCONI	Director	February 29, 2016
(James W. Cicconi)

/s/ EDWARD ESCUDERO	Director	February 29, 2016
(Edward Escudero)

/s/ JAMES W. HARRIS	Director	February 29, 2016
(James W. Harris)

/s/ PATRICIA Z. HOLLAND-BRANCH	Director	February 29, 2016
(Patricia Z. Holland-Branch)

/s/ WOODLEY L. HUNT	Director	February 29, 2016
(Woodley L. Hunt)

/s/ THOMAS V. SHOCKLEY III	Director	February 29, 2016
(Thomas V. Shockley III)

/s/ ERIC B. SIEGEL	Director	February 29, 2016
(Eric B. Siegel)

/s/ STEPHEN N. WERTHEIMER	Director	February 29, 2016
(Stephen N. Wertheimer)

/s/ CHARLES A. YAMARONE	Director	February 29, 2016
(Charles A. Yamarone)