Edgar Filing: EL PASO ELECTRIC CO /TX/

Since 1999
(a)

Authorized
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Shares repurchased (b)

Cost, including commission (in thousands)

Total remaining shares available for repurchase at December 31, 2014

2014 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, 2014



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	¨

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

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

As of June 30, 2014, the aggregate market value of the voting stock held by non-affiliates of the registrant was $1,597,139,431 (based on the closing price as quoted on the New York Stock Exchange on that date).

As of January 31, 2015, there were 40,352,478 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 2015 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 Updates
Company		El Paso Electric Company
DOE		United States Department of Energy
El Paso		City of El Paso, Texas
FASB		Financial Accounting Standards Board
FERC		Federal Energy Regulatory Commission
Fort Bliss		Fort Bliss, the United States Army post next to El Paso, Texas
Four Corners		Four Corners Generating Station
kV		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 which a generating plant can supply under specified conditions for a given time interval, without exceeding approved limits of temperature and stress
NRC		Nuclear Regulatory Commission
Palo Verde		Palo Verde Nuclear Generating Station
Palo Verde Participants		Those utilities who share in power and energy entitlements, and bear certain allocated costs, with respect to Palo Verde pursuant to the ANPP Participation Agreement
PNM		Public Service Company of New Mexico
PUCT		Public Utility Commission of Texas
RGEC		Rio Grande Electric Cooperative
RGRT		Rio Grande Resources Trust
TEP		Tucson Electric Power Company



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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	41
8	Financial Statements and Supplementary Data	43
9	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	100
9A	Controls and Procedures	100
9B	Other Information	100

	PART III
10	Directors, Executive Officers and Corporate Governance	101
11	Executive Compensation	101
12	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	101
13	Certain Relationships and Related Transactions, and Director Independence	101
14	Principal Accounting Fees and Services	101

	PART IV
15	Exhibits and Financial Statement Schedules	102



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FORWARD-LOOKING STATEMENTS

Certain matters discussed in this Annual Report on Form 10-K other than statements of historical information are "forward-looking statements." The Private Securities Litigation Reform Act of 1995 has established that these statements qualify for safe harbors from liability. Forward-looking statements may include words like we "believe", "anticipate", "target", "expect", "predict", "pro forma", "estimate", "intend", "will", "is designed to", "plan" and words of similar meaning. Forward-looking statements describe our future plans, objectives, expectations or goals. Such statements address future events and conditions concerning and include, but are not limited to, such things as:


•	capital expenditures,


•	earnings,


•	liquidity and capital resources,


•	ratemaking/regulatory matters,


•	litigation,


•	accounting matters,


•	possible corporate restructurings, acquisitions and dispositions,


•	compliance with debt and other restrictive covenants,


•	interest rates and dividends,


•	environmental matters,


•	nuclear operations, and


•	the overall economy of our service area.

These forward-looking statements involve known and unknown risks that may cause our actual results in future periods to differ materially from those expressed in any forward-looking statement. Factors that would cause or contribute to such differences include, but are not limited to, such things as:


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


•	the ability of our operating partners to maintain plant operations and manage operation and maintenance costs at the Palo Verde and Four Corners plants, including costs to comply with any new or expanded regulatory or environmental requirements,


•	reductions in output at generation plants operated by us,


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


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


•	potential delays in our construction schedule,


•	disruptions in our transmission system, and in particular the lines that deliver power from our remote generating facilities,


•	electric utility deregulation or re-regulation,


•	regulated and competitive markets,


•	ongoing municipal, state and federal activities,


•	economic and capital market conditions,


•	changes in accounting requirements and other accounting matters,


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


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


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



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


•	cuts in military spending or shutdowns of the federal government that reduce demand for our services from military and governmental customers,


•	political, legislative, judicial and regulatory developments,


•	the impact of lawsuits filed against us,


•	the impact of changes in interest rates,


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


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


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


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


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


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


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


•	possible income tax and interest payments as a result of audit adjustments proposed by the IRS or state taxing authorities,


•	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 report should be read in its entirety. No one section of this report deals with all aspects of the subject matter. Any forward-looking statement speaks only as of the date such statement was made, and we are not obligated to update any forward-looking statement to reflect events or circumstances after the date on which such statement was made, except as required by applicable laws or regulations.



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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 1,879 MW. For the year ended December 31, 2014, the Company’s energy sources consisted of approximately 47% nuclear fuel, 35% natural gas, 5% coal, 13% purchased power and less than 1% generated by Company-owned solar photovoltaic panels and wind turbines. The Company's current generation portfolio exhibits lower carbon intensity than most other electric utilities in the southwestern United States and the Company continues to expand its portfolio of renewable energy sources, particularly solar photovoltaic generation. As of December 31, 2014, the Company has power purchase agreements for 107 MW from solar photovoltaic generation facilities. (See "Energy Sources- Purchased Power").

The Company serves approximately 399,000 residential, commercial, industrial, public authority and wholesale customers. The Company distributes electricity to retail customers principally in El Paso, Texas and Las Cruces, New Mexico (representing approximately 62% and 12%, respectively, of the Company’s retail revenues for the year ended December 31, 2014). In addition, the Company’s wholesale sales include sales for resale to other electric utilities and power marketers. Principal industrial, public authority and other large retail customers of the Company include United States military installations, including Fort Bliss in Texas and White Sands Missile Range and Holloman Air Force Base in New Mexico, an oil refinery, 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, 2015, the Company had approximately 1,000 employees, 38% of whom are covered by a collective bargaining agreement.

The Company makes available free of charge through its website, www.epelectric.com, its annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, 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 into this document by reference.

Facilities

As of December 31, 2014, the Company’s net dependable generating capability of 1,879 MW consists of the following:



Station	Primary Fuel Type	Company's Share of Net Dependable Generating Capability * (MW)	Company Ownership Interest		Location
Palo Verde	Nuclear	633	15.8	%	Wintersburg, Arizona
Newman Power Station	Natural Gas	752	100	%	El Paso, Texas
Rio Grande Power Station	Natural Gas	321	100	%	Sunland Park, New Mexico
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		1,879

____________________

* 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 Station

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

•

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 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, 2014, the Company's decommissioning trust fund had a balance of $234.3 million. Although the 2013 Study was based on the latest available information, there can be no assurance that decommissioning cost estimates will not increase in the future or that regulatory requirements will not change.

•

Spent Fuel Storage. Pursuant to the Nuclear Waste Policy Act of 1982, as amended in 1987 (the "NWPA"), the DOE is legally obligated to accept and dispose of all spent nuclear fuel and other high-level radioactive waste generated by all domestic power reactors by 1998. The DOE's obligations are reflected in a contract for Disposal of Spent Nuclear Fuel and/or High-Level Radioactive Waste (the "Standard Contract") with each nuclear power plant. The DOE failed to begin accepting spent nuclear fuel by 1998. On December 19, 2012, APS, acting on behalf of itself and the participant owners of Palo Verde, filed a second breach of contract lawsuit against the DOE. This lawsuit 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 owners 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 participant owners of Palo Verde, 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 total submitted claim amount was $42.5 million, of which the Company's portion is $6.7 million. The reimbursement is anticipated to be received in the first half of 2015, and the majority will be refunded to customers through the applicable fuel adjustment clauses.

•

DOE’s Construction Authorization Application for Yucca Mountain. The DOE had planned to meet its disposal obligations by designing, licensing, constructing, and operating a permanent geologic repository 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.

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.

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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 had 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 had 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 24 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.

The NRC has issued a series of interim staff guidance documents regarding implementation of these requirements. Due to the developing nature of these requirements, the Company cannot predict the ultimate financial or operational impacts on Palo Verde or the Company; however, the NRC has directed nuclear power plants to implement the first tier recommendations of the NRC’s Near Term Task Force. In response to these recommendations, Palo Verde expects to spend approximately $40 million for capital enhancements to the plant over the next two years (the Company's share is $6.3 million) in addition to the approximate $80 million (the Company’s share is $12.6 million) that has already been spent on capital enhancements as of December 31, 2014.

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•

Liability and Insurance Matters. The Palo Verde Participants have insurance for public liability resulting from nuclear energy hazards, covered by primary liability insurance provided by commercial insurance carriers and an industry-wide retrospective assessment program. If a loss at a nuclear power plant covered by the programs exceeds the accumulated funds in the primary level of protection, the Company could be assessed retrospective premium adjustments on a per incident basis up to $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 $2.3 billion. In addition, the Company has secured insurance against portions of any increased cost of generation or purchased power and business interruption resulting from a sudden and unforeseen outage at Palo Verde.

Fossil-Fueled Plants

The 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 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 located on land under easements from the federal government and a lease from the Navajo Nation that expires in 2016. APS, on behalf of the Four Corners participants, negotiated amendments to the lease with the Navajo Nation which extended the lease from 2016 to 2041, pending the approval of the Department of the Interior and a Federal environmental review.

The 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 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 “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, which is expected to occur not later than July 2016, subject to the receipt of regulatory approvals. 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, three 500 kV lines in Arizona, and owns the transmission and distribution network within its New Mexico and Texas retail service area and operates these facilities under franchise agreements with various municipalities. The Company is also a party to various transmission and power exchange agreements that, together with its owned transmission lines, enable the Company to deliver its energy entitlements from its remote generation sources at Palo Verde and Four Corners to its service area. Pursuant to standards established by the North American Electric Reliability Corporation and the Western Electricity Coordinating Council, the Company operates its transmission system in a way that allows it to maintain system integrity in the event that any one of these transmission lines is out of service.

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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 TEP's Springerville Generating Plant near Springerville, Arizona, to the Company's Diablo Substation near Sunland Park, New Mexico.


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


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

(4) Runs from the Company's and PNM's high voltage direct current terminal at the Eddy County Substation near Artesia, New Mexico to the AMRAD Substation near Oro Grande, New Mexico. Due to damage caused by severe weather conditions which occurred in November and December of 2013, this transmission line is not currently in service. The Company currently anticipates that this line will return to service before May 2015.


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

See Part II, Item 8, "Financial Statements and Supplementary Data – Note K, Commitments, Contingencies and Uncertainties- Environmental Matters of Notes to Financial Statements" 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.

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The Company’s estimated cash construction costs for 2015 through 2019 are approximately $1.1 billion. Actual costs may vary from the construction program estimates shown. Such estimates are reviewed and updated periodically to reflect changed conditions.



By Year (1)(2)(3) (estimates in millions)			By Function (estimates in millions)
2015	$	271	Production (1)(2)(3)	$	514
2016	203		Transmission	156
2017	170		Distribution	332
2018	199		General	95
2019	254
Total	$	1,097	Total	$	1,097

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

(2)

$514 million has been allocated for new generating capacity of which $136 million is to construct four units of the Montana Power Station (the "MPS"). The $136 million consist of $11 million to complete construction of two 88 MW gas-fired LMS-100 units that are scheduled to come on line before March 31, 2015 and $112 million for two additional 88 MW gas fired LMS-100 units scheduled to come on line before the summer peak in 2016 and 2017. An additional $13 million of common costs is associated with the development of the MPS common facilities. In addition to the construction costs for the MPS, $155 million of construction costs are included from 2018 through 2019 for a combined cycle unit scheduled to be completed in 2022. In addition to construction costs for new generating capacity, generation costs include $24 million for other local generation, $13 million for Four Corners (which excludes costs for pollution control equipment that would be placed in service after the Company’s planned exit in July 2016), and $186 million for Palo Verde. The Company plans to deactivate Rio Grande Power Station Unit 6 (“Rio Grande 6”) before the peak demand of 2015. Rio Grande 6 is a 45 MW steam-electric generating unit which was originally placed in service in 1957. The Company may decide to reactivate Rio Grande 6 if needed. Additionally, as noted above, the Company intends to cease its participation in Four Corners in 2016.


(3)	Does not include four utility-scale solar energy generating facilities that may result from a recent request for proposal (RFP). These solar projects could have a combined maximum capacity up to 30 MW.

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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,
	2014		2013		2012
Power Source	(percentage of energy mix)
Nuclear	47	%	46	%	46	%
Natural gas	35		34		32
Coal	5		6		6
Purchased power	13		14		16
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 $110 million aggregate principal amount borrowed in the form of senior notes, of which $15 million will mature in August 2015. The Company will either repay or refinance the $15 million of senior notes upon maturity. 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 supply contract and spot market purchases. The long-term supply contract provides for firm deliveries of gas at market-based index prices. In 2014, the Company’s natural gas requirements at the Newman and Rio Grande Power Stations were met with both short-term and long-term natural gas purchases from various suppliers, and this practice is expected to continue in 2015. Interstate gas is delivered under a base firm transportation contract. The Company has expanded its firm interstate transportation contract to include the MPS. The Company anticipates it will continue to purchase natural gas at spot market prices on a monthly basis for a portion of the fuel needs for the Newman, Rio Grande and the MPS. The Company will continue to evaluate the availability of short-term natural gas supplies versus long-term supplies to maintain a reliable and economical supply for its local generating stations.

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

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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.

Purchased Power

The Company has a firm 100 MW Power Purchase and Sale Agreement with Freeport-McMoran Copper and Gold Energy Services LLC ("Freeport") which provides for Freeport to deliver energy to the Company from its ownership interest in the Luna Energy Facility (a natural gas-fired combined cycle generation facility located in Luna County, New Mexico) and for the Company to deliver a like amount of energy at Greenlee, Arizona. The Company may purchase up to the contracted MW amount at a specified price at times when energy is not exchanged under the Power Purchase and Sale Agreement. Upon mutual agreement, the contract allows the parties to increase the amount of energy that is purchased and sold under the Power Purchase and Sale Agreement. The parties have agreed to increase the amount to 125 MW through December 2015. The contract was approved by the FERC and continues through December 31, 2021. On December 30, 2014, the FERC issued an order authorizing the disposition, i.e. sale, of Freeport's interest in the Luna facility to Samchully Power & Utilities 1, LLC. Freeport will retain the ability to purchase up to the full amount of its previous ownership share of the Luna facility of approximately 190 MW, thereby continuing to fulfill its obligations pursuant to the Power Purchase and Sale Agreement.

The Company has a 25-year purchase power agreement with Hatch Solar Energy Center I, LLC for a 5 MW solar photovoltaic project located in southern New Mexico which began commercial operation in July 2011. The Company entered into a 20-year contract with NRG Solar Roadrunner, LLC ("NRG") for the purchase of all of the output of a 20 MW solar photovoltaic plant built in southern New Mexico which began commercial operation in August 2011. The Company has 25-year purchase power agreements to purchase all of the output of two additional solar photovoltaic projects located in southern New Mexico, SunEdison 1 (10 MW) and SunEdison 2 (12 MW) which achieved commercial operation on June 25, 2012 and May 2, 2012, respectively. The Company entered into these contracts to help meet its renewable portfolio requirements. 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 on May 23, 2014. The Company has a 30-year purchase power agreement with PSEG El Paso Solar Energy Center ("PSEG") to purchase the total output of approximately 10 MW from a solar photovoltaic generation plant that PSEG owns and operates on land subleased from the Company in proximity to its Newman Generation Station. This solar project achieved commercial operation on December 30, 2014.

The Company entered into an agreement in 2009 to purchase capacity of up to 40 MW and unit contingent energy during 2010 from Shell Energy North America ("Shell"). Under the agreement, the Company provided natural gas to Pyramid Unit No. 4 where Shell had the right to convert natural gas to electric energy. The Company entered into a contract with Shell on May 17, 2010 to extend the term of the capacity and unit contingent energy purchase from January 1, 2011 through September 30, 2014.

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Other purchases of shorter duration were made during 2014 to supplement the Company's generation resources during planned and unplanned outages and for economic reasons as well as to supply off-system sales.

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Operating Statistics



	Years Ended December 31,
	2014		2013		2012
Operating revenues (in thousands):
Non-fuel base revenues:
Retail:
Residential	$	234,371	$	236,651	$	234,095
Commercial and industrial, small	185,388		184,568		188,014
Commercial and industrial, large	39,239		40,235		42,041
Sales to public authorities	92,066		95,044		96,132
Total retail base revenues	551,064		556,498		560,282
Wholesale:
Sales for resale	2,277		2,172		2,318
Total non-fuel base revenues	553,341		558,670		562,600
Fuel revenues:
Recovered from customers during the period	161,052		133,481		130,193
Under (over) collection of fuel	3,110		10,849		(18,539		)
New Mexico fuel in base rates	71,614		73,295		74,154
Total fuel revenues	235,776		217,625		185,808
Off-system sales:
Fuel cost	74,716		68,241		62,481
Shared margins	21,117		13,016		9,191
Retained margins	2,147		1,549		1,098
Total off-system sales	97,980		82,806		72,770
Other	30,428		31,261		31,703
Total operating revenues	$	917,525	$	890,362	$	852,881
Number of customers (end of year) (1):
Residential	353,885		349,629		345,567
Commercial and industrial, small	40,038		39,164		38,494
Commercial and industrial, large	49		50		50
Other	5,017		5,043		4,896
Total	398,989		393,886		389,007
Average annual kWh use per residential customer	7,496		7,701		7,712
Energy supplied, net, kWh (in thousands):
Generated	9,477,129		9,288,773		9,262,133
Purchased and interchanged	1,390,490		1,547,930		1,768,810
Total	10,867,619		10,836,703		11,030,943
Energy sales, kWh (in thousands):
Retail:
Residential	2,640,535		2,679,262		2,648,348
Commercial and industrial, small	2,357,846		2,349,148		2,366,541
Commercial and industrial, large	1,064,475		1,095,379		1,082,973
Sales to public authorities	1,562,784		1,622,607		1,617,606
Total retail	7,625,640		7,746,396		7,715,468
Wholesale:
Sales for resale	61,729		61,232		64,266
Off-system sales	2,609,769		2,472,622		2,614,132
Total wholesale	2,671,498		2,533,854		2,678,398
Total energy sales	10,297,138		10,280,250		10,393,866
Losses and Company use	570,481		556,453		637,077
Total	10,867,619		10,836,703		11,030,943
Native system:
Peak load, kW	1,766,000		1,750,000		1,688,000
Net dependable generating capability for peak, kW	1,879,000		1,852,000		1,765,000
Total system:
Peak load, kW (2)	2,001,000		1,883,000		1,979,000
Net dependable generating capability for peak, kW	1,879,000		1,852,000		1,765,000

___________________________


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


(2)	Includes spot sales and net losses of 235,000 kW, 133,000 kW and 291,000 kW for 2014, 2013 and 2012, 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 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.

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. In a proposal for decision issued on October 7, 2014, the Administrative Law Judge (“ALJ”) recommended approval of the Company’s requested cost recovery including the requested bonus. The PUCT approved the ALJ’s recommendation at its November 14, 2014 open meeting. The PUCT decision was not appealed. The Company recorded the $2.0 million bonus as operating revenue in the fourth quarter of 2014.

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, 2014, the Company filed a request, which was assigned PUCT Docket No. 42384, to increase its fixed fuel factor by $10.7 million or 6.9% annually, pursuant to its approved formula. The revised fixed fuel factor reflected an expected increase in prices for natural gas over the twelve month period beginning March 2014. The increase in the fixed fuel factor received final approval on May 28, 2014 and was effective with May 2014 billings. As of December 31, 2014, the Company had under-recovered fuel costs in the amount of $10.2 million for the Texas jurisdiction. The Company has been reducing the amount of the under-recovery since August 2014 and expects to continue to reduce the amount of under-recovery as long as the price of natural gas remains below the cost of natural gas included in its current fixed fuel factor. If the price of natural gas increases above the cost of natural gas included in the current fixed fuel factor, the Company may request an increase to the fixed fuel factor and effectively mitigate an increase in the under-recovery balance. If the under-recovered balance is above the materiality threshold at the time the fixed fuel factor increase is requested, then the Company will consider requesting a fuel surcharge to collect the remaining under-recovered balance.

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City of El Paso approximately $0.1 million in incurred expenses. The settlement also provides that 100% of margins on non-arbitrage off-system sales (as defined by the settlement) and 50% of margins on arbitrage off-system sales be shared with its Texas customers beginning April 1, 2014. For the period April 1, 2014 through June 30, 2015, the Company’s total share of margins assignable to 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. The Company also agreed to file with the PUCT a proceeding to address the reasonableness of the Company’s decision to not continue to participate in the Four Corners coal-fired generating Units 4 and 5 after July 2016. It is expected that issues related to the final coal mine closing and reclamation costs will be addressed in that proceeding as well as other issues related to post-participation events such as the asset retirement obligations of the Company related to those two units. The PUCT’s final order completes the regulatory review and reconciliation of the Company’s fuel expenses for the period through March 31, 2013.

Montana Power Station Approvals. As discussed further below, the Company has received a Certificate of Convenience and Necessity ("CCN") from the PUCT to construct all four units of the MPS in El Paso County, Texas. The Company also obtained air permits from the Texas Commission on Environmental Quality ("TCEQ") and the EPA.

On June 23, 2014, the U.S. Supreme Court issued an opinion in the Utility Air Regulatory Group vs EPA regarding EPA’s authority to require GHG PSD permits for stationary sources. The opinion concluded that the EPA erred in making applicability of the CAA permitting requirements based on GHG emissions. As a result, the Company believes its EPA air permit is no longer required and could be rescinded, and it is eligible for a standard air permit to replace the new source review permit issued by the TCEQ. Accordingly, on August 1, 2014, the Company submitted a request to the EPA to rescind the EPA air permit which request remains pending. Also, on September 16, 2014, the Company applied for a standard air permit, which TCEQ issued on October 2, 2014.

On December 13, 2012, in PUCT Docket No. 40301, the Company received CCN approval from the PUCT for MPS Units 1 and 2. On September 6, 2013, the Company filed an application with the PUCT for issuance of a CCN to construct, own and operate two additional 88 MW natural gas-fired generating units designated as the MPS Units 3 and 4. The case was designated PUCT Docket No. 41763. Hearings in this case were held before an ALJ in February 2014. On July 11, 2014, the PUCT approved the CCN to construct MPS Units 3 and 4.

In 2013, the Company filed three transmission line CCN applications with the PUCT as part of the MPS Project:


•	MPS to Caliente: a 115-kV transmission line from the MPS to the existing Caliente Substation in east El Paso. (PUCT Docket No. 41360)


•	MPS In & Out: a 115-kV transmission line from the MPS to intersect with the existing Caliente - Coyote 115-kV transmission line. (PUCT Docket No. 41359)


•	MPS to Montwood: a 115-kV transmission line from the MPS to the existing Montwood Substation in east El Paso. (PUCT Docket No. 41809)

The Company requested to build these transmission lines to connect the new MPS to the electrical grid in order to meet expected customer growth and electric demand and to improve system reliability. On March 10, 2014, the PUCT issued a final order approving a unanimous settlement in the MPS to Caliente transmission CCN filing. On August 18, 2014, the PUCT issued final orders approving unanimous settlements of the MPS In & Out transmission CCN filing and the MPS to Montwood transmission CCN filing.

Other Required Approvals. The Company has obtained other required approvals for recovery of fuel costs through fixed fuel factors, other tariffs and approvals as required by the Public Utility Regulatory Act ( the "PURA") and the PUCT.

New Mexico Regulatory Matters

2009 New Mexico Stipulation. On December 10, 2009, the NMPRC issued a final order conditionally approving the stipulated rates in NMPRC Case No. 09-00171-UT. The stipulated rates went into effect with January 2010 bills. The stipulated rates provide for an Efficient Use of Energy Factor Rate Rider to recover energy efficiency expenditures which requires an annual filing and approval of the related incentives and adjustment to the recovery factors.

Fuel and Purchased Power Costs. Fuel and purchased power costs are recovered through base rates and a Fuel and Purchased Power Cost Adjustment Clause (the "FPPCAC") that corrects for changes in the costs of fuel 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 its investment in Palo Verde Unit 3 in New Mexico through the FPPCAC as purchased power using a proxy market price approved in the 2009 New Mexico rate stipulation.

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Montana Power Station Approvals. The Company has received a CCN from the NMPRC to construct all four units of the MPS and associated transmission lines. The Company also obtained all necessary air permits from the TCEQ and EPA and has begun construction. 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.

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

Federal Regulatory Matters

Public Service Company of New Mexico's ("PNM") 2010 Transmission Rate Case. On October 27, 2010, PNM filed a Notice of Transmission Rate Change for transmission delivery services provided by PNM. These rates went into effect on June 1, 2011. The Company takes transmission service from PNM. On January 2, 2013, the FERC issued a letter order approving a unanimous stipulation and agreement. Pursuant to the stipulation, on January 31, 2013, PNM refunded $1.9 million for amounts that PNM collected since June 1, 2011 in excess of settlement rates. This amount was recorded in the fourth quarter of 2012 as a reduction of transmission expense.

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. The parties to the case, including the Company, have been participating in settlement negotiations. The Company cannot predict the outcome of the case at this time.

Issuance of Long-Term Debt and Guarantee of Debt. In the fourth quarter of 2013, the Company received approval from the FERC to incrementally issue up to $300 million of long-term debt and to guarantee the issuance of up to $50 million of new long-term debt by RGRT to finance future purchases of nuclear fuel and to refinance existing nuclear fuel debt obligations. The FERC approval was effective on November 15, 2013 and terminates two years thereafter. The $150 million in aggregate principal amount of 5.00% Senior Notes issued in December 2014 were issued pursuant to this approval. The authorization to issue up to an additional $150 million of long-term debt and up to $50 million of new long-term debt by RGRT provides the Company with the flexibility to access the debt capital markets prior to the termination of the FERC approval on November 15, 2015. Additionally, the Company could request approval from the FERC to issue additional debt after November 15, 2015. The Company may decide to issue long-term debt in the capital markets to finance capital requirements in late 2015 or early 2016.

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 granted by the DOE and two presidential permits.

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

Sales for Resale

The Company provides firm capacity and associated energy to the 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

El Paso and Las Cruces Franchises

The Company has a franchise agreement with El Paso, the largest city it serves. The franchise agreement allows the Company to utilize public rights-of-way necessary to serve its retail customers within El Paso. The Company is also providing electric distribution service to Las Cruces under an implied franchise by satisfying all obligations under the franchise agreement that expired on April 30, 2009.

The franchise arrangements held between the Company and the cities of El Paso and Las Cruces are detailed below:



City	Period	Franchise Fee	(a)
El Paso	August 1, 2010 - Present	4.00%	(b)
Las Cruces	February 1, 2000 - Present	2.00%

(a) Based on a percentage of revenue.

(b) 0.75% of the El Paso franchise fee is to be placed in a restricted fund to be used solely for economic development and renewable energy purposes.

Military Installations

The Company serves Holloman Air Force Base ("Holloman"), White Sands Missile Range ("White Sands") and Fort Bliss. The military installations represent approximately 5% of the Company's annual retail revenues. 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 is serving White Sands under the applicable New Mexico tariffs. In March 2006, the Company signed a contract with Holloman that provides for the Company to provide retail electric service and limited wheeling services to Holloman for a ten-year term which expires in January 2016 .

Other Information

Investors should note that we announce material financial information in our filings with the SEC, press releases and public conference calls. Based on guidance from the SEC, we may also use the Investor Relations section of our website (www.epelectric.com) to communicate with investors about our company. It is possible that the financial information we post there could be deemed to be material information. The information on our website is not part of this document.

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Executive Officers of the Registrant

The executive officers of the Company are elected annually and serve at the discretion of the Board of Directors. The executive officers of the Company as of February 27, 2015, were as follows:



Name	Age	Current Position and Business Experience
Thomas V. Shockley III	69	Chief Executive Officer since May 2012; Interim Chief Executive Officer from January 2012 to May 2012; Non-Employee Member of the Board of Directors from May 2010 to January 2012; Vice – Chairman and Chief Operating Officer for American Electric Power from June 2000 to August 2004; retired in 2004.
Mary E. Kipp	47	President since September 2014; Senior Vice President, General Counsel and Chief Compliance Officer from June 2010 to September 2014; Vice President – Legal and Chief Compliance Officer from December 2009 to June 2010.
Nathan T. Hirschi	51	Senior Vice President and Chief Financial Officer since October 2013; Vice President and Controller from March 2010 to October 2013; Vice President – Special Projects from December 2009 to February 2010.
Steven T. Buraczyk	47	Senior Vice President – Operations since October 2013;Vice President of Regulatory Affairs from April 2013 to October 2013; Vice President of Power Marketing and Fuels and Resource and Delivery Planning from August 2012 to April 2013; Vice President – System Operations and Planning from January 2011 to August 2012; Vice President – Power Marketing and Fuels from July 2008 to January 2011.
Rocky R. Miracle	62	Senior Vice President – Corporate Planning & Development and Chief Compliance Officer since September 2014; Senior Vice President – Corporate Planning and Development from August 2009 to September 2014.
William A. Stiller	63	Senior Vice President – Human Resources and Customer Care since October 2013; Vice President and Chief Human Resources Officer from January 2013 to October 2013; Independent Human Resources consultant from 2005 to 2013.
John R. Boomer	53	Vice President – General Counsel since September 2014; 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	62	Vice President – Controller since September 2014; Chief Financial Officer – Vice President for ReadyOne Industries, Inc. from June 2006 to September 2014.

Item 1A. Risk Factors

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

Our Revenues and Profitability Depend upon Regulated Rates

Our retail rates are subject to regulation by incorporated municipalities in Texas, the PUCT, the NMPRC and the FERC. The settlement approved in the Company's 2012 Texas rate case, PUCT Docket No. 40094, established the Company's current retail base rates in Texas, effective May 1, 2012. In addition, the settlement in the Company's 2009 New Mexico rate case, NMPRC Case No. 09‑00171‑UT, established rates in New Mexico that became effective on January 2010.

Our profitability depends on our ability to recover the costs, including a reasonable return on invested capital, of providing electric service to our customers through base rates approved by our regulators. These rates are generally established based on an analysis of the expenses we incur in a historical test year, and as a result, the rates ultimately approved by our regulators may or may not match our expenses at any given time and recovery of expenses may lag behind the occurrence of those expenses. Rates in New Mexico may be established using projected costs and investment for a future test year period in certain instances. While rate regulation is based on the assumption that we will have a reasonable opportunity to recover our costs and earn a reasonable rate of return on our invested capital, there can be no assurance that our future Texas rate cases or New Mexico rate

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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 asset retirement obligations. It is also likely that third parties will intervene in any rate cases and challenge whether our costs are reasonable and necessary. If all of our costs are not recovered through the retail base rates ultimately approved by our regulators, our profitability and cash flow could be adversely affected which, over time, could adversely affect our ability to meet our financial obligations.

We May Not Be Able To Recover All Costs of New Generation 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 Montana Power Station, 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. We have risk related to recovering all costs associated with the construction of Rio Grande Unit 9, the Montana Power Station, 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 revolving credit facility, which was amended and restated on January 14, 2014, could help fund the construction of the Montana Power Station and other capital additions. The costs of financing and constructing these assets will be reviewed in future rate cases in both Texas and New Mexico. To the extent that the PUCT or the NMPRC determines that the costs of construction are not reasonable because of cost overruns, delays or other reasons, we may not be allowed to recover these costs from customers in base rates.

In addition, if these units are not completed on time, we may be required to purchase power or operate less efficient generating units to meet customer requirements. Any replacement purchased power or fuel costs will be subject to regulatory review by the PUCT and the NMPRC. We face financial risks to the extent that recovery is not allowed for any replacement fuel costs resulting from delays in the completion of these new units or other new units.

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

In recent years, the global credit and equity markets and the overall economy have been through a state of turmoil. These and future events could have a number of effects on our operations and our capital programs. For example, tight credit and capital markets could make it difficult and more expensive to raise capital to fund our operations and capital programs. If we are unable to access the credit markets, we could be required to defer or eliminate important capital projects in the future. In addition, declines in the stock market performance may reduce the value of our financial assets and decommissioning trust investments. Such market results may also increase our funding obligations for our pension plans, other post-retirement benefit plans and nuclear decommissioning trusts. Changes in the corporate interest rates which we use as the discount rate to determine our pension and other post-retirement liabilities may have an impact on our funding obligations for such plans and trusts. Further, continued economic volatility may result in reduced customer demand, both in the retail and wholesale markets, and increases in customer delinquencies and write-offs. Similarly, actions or inaction of Congress and of governmental agencies can impact our operations. For example, during 2013, sales to public authorities and small commercial and industrial customers were negatively impacted by the federal government sequestration and shutdown.The credit markets and overall economy may also adversely impact the financial health of our suppliers. If that were to occur, our access to and prices for inventory, supplies and capital equipment could be adversely affected. Our power trading counterparties could also be adversely impacted by the market and economic conditions which could result in reduced wholesale power sales or increased counterparty credit risk. Declines in revenues, earnings and cash flow from these events, could impact our ability to fund construction expenditures and impact the level of dividend payments. This is not intended to be an exhaustive list of possible effects, and we may be adversely impacted in other ways.

Our Costs Could Increase or We Could Experience Reduced Revenues if

There are Problems at the Palo Verde Nuclear Generating Station

A significant percentage of our generating capacity, off-system sales margins, assets and operating expenses is attributable to Palo Verde. Our 15.8% interest in each of the three Palo Verde units totals approximately 633 MW of generating capacity. Palo Verde represents approximately 34% of our available net generating capacity and provided approximately 47% of our energy requirements for the twelve months ended December 31, 2014. Palo Verde comprises approximately 29% of our total net plant-in-service and Palo Verde expenses comprise a significant portion of operation and maintenance expenses. APS is the operating agent for Palo Verde, and we have limited ability under the ANPP Participation Agreement to influence operations and costs at

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Palo Verde. Palo Verde operated at a capacity factor of 93.7% and 91.1% in the twelve months ended December 31, 2014 and 2013, respectively.

Our ability to increase retail base rates in Texas and New Mexico is limited. We cannot assure that revenues will be sufficient to recover any increased costs, including any increased costs in connection with Palo Verde or other operations, whether as a result of inflation, changes in tax laws, regulatory requirements, the costs of securing the facilities against possible terrorist attacks, cyber attacks, or other causes.

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 time the balance exceeds a threshold material amount and is expected to continue to be materially under-recovered. During periods of significant increases in natural gas prices, the Company realizes a lag in the ability to reflect increases in fuel costs in its fuel recovery mechanisms in Texas. As a result, cash flow is impacted due to the lag in payment of fuel costs and collection of fuel costs from customers. To the extent the fuel and purchased power recovery processes in Texas and New Mexico do not provide for the timely recovery of such costs, we could experience a material negative impact on our cash flow. At December 31, 2014 and 2013, the Company had a net under-collection balance of $9.3 million and $6.2 million, respectively.

Equipment Failures and Other External Factors Can Adversely Affect Our Results

The generation and transmission of electricity require the use of expensive and complex equipment. While we have a maintenance program in place, generating plants are subject to unplanned outages because of equipment failure and severe weather conditions. The advanced age of several of our gas-fired generating units in or near El Paso increases the vulnerability of these units. In the event of unplanned outages, we must acquire power from others at unpredictable costs in order to supply our customers and comply with our contractual agreements. This additional purchased power cost would be subject to review and approval of the PUCT and the NMPRC in reconciliation proceedings. As noted above, in the event that recovery for fuel and purchased power expenses could differ from the amounts we are allowed to collect from our customers, we would incur a loss to the extent of the disallowance. This can materially increase our costs and prevent us from selling excess power at wholesale. In addition, actions of other utilities may adversely affect our ability to use transmission lines to deliver or import power, thus subjecting us to unexpected expenses or to the cost and uncertainty of public policy initiatives. Concerns over physical security and cyber security of transmission lines and generation facilities is also increasing, which may require us to incur additional capital and operating costs. 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, are largely beyond our control, but may have a material adverse effect on our earnings, cash flow and financial position.

Competition and Deregulation Could Result in a Loss of Customers and Increased Costs

As a result of changes in federal law, our wholesale and large retail customers already have access to, in varying degrees, alternative sources of power, including co-generation of electric power. Deregulation legislation is in effect in Texas requiring us to separate our transmission and distribution functions, which would remain regulated, from our power generation and energy services businesses, which would operate in a competitive market, in the future. In 2004, the PUCT approved a rule delaying retail competition in our Texas service territory. This rule was codified in the PURA in June 2011. The PURA identifies various milestones

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that we must reach before retail competition can begin. The first milestone calls for the development, approval by the FERC, and commencement of independent operation of a regional transmission organization in the area that includes our service territory. This and other milestones are not likely to be achieved for a number of years, if they are achieved at all. There is substantial uncertainty about both the regulatory framework and market conditions that would exist if and when retail competition is implemented in our Texas service territory, and we may incur substantial preparatory, restructuring and other costs that may not ultimately be recoverable. There can be no assurance that deregulation would not adversely affect our future operations, cash flow and financial condition.

Future Costs of Compliance with Environmental Laws and Regulations Could

Adversely Affect Our Operations and Financial Results

We are or may become 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 could also result in limitations in operating hours and/or changes in construction schedules for future generating units.

Costs of compliance with environmental laws and regulations or fines or penalties resulting from non-compliance, if not recovered in our rates, could adversely affect our operations and/or financial results, especially if emission and/or discharge limits are tightened, more extensive permitting requirements are imposed, additional substances become regulated and the number and types of assets we operate 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 proposed revision of the existing primary and secondary ground-level ozone National Ambient Air Quality Standards. 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 GHGs (including carbon dioxide) through the operation of its power plants. Federal legislation had been introduced in both houses of Congress to regulate the emission of GHGs and numerous states have adopted programs to stabilize or reduce GHG emissions. Additionally, the EPA is proceeding with regulation of GHG under the CAA. Under EPA regulations finalized in May 2010, 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 January 2014, the EPA published a proposal to establish new source performance standards limiting GHG emission from electric generating units on which construction commences after that date. Also, in June 2014, the EPA proposed carbon dioxide emissions standards for existing and reconstructed /modified power plants. EPA expects to issue final rules for carbon dioxide emissions from new, existing and reconstructed/modified power plants by summer 2015. The potential impact of these 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 currently 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.

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

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tax requirements. Our information technology networks and infrastructure may be vulnerable to damage, disruptions or shutdowns due to attacks by hackers, breaches due to employee error or malfeasance, system failures, natural disasters, a physical attack on our facilities, or other catastrophic events. The occurrence of any of these events could impact the reliability of our generation, transmission and distribution systems and energy marketing and trading functions; could expose us or our customers or employees to a risk of loss or misuse of information; and could result in legal claims or proceedings, liability or regulatory penalties against us, damage our reputation or otherwise harm our business.

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

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.

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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 in El Paso. The Company leases land in El Paso adjacent to the Newman Power Station under a lease which expires in June 2033 with a renewal option of 25 years. The Company also leases certain warehouse facilities in El Paso under a lease which expires in December 2015. The Company has several other leases for office and parking facilities which expire within the next three years.


Item 3.	Legal Proceedings

The Company is a party to various legal actions. In many of these matters, the Company has excess casualty liability insurance that covers the various claims, actions and complaints. Based upon a review of these claims and applicable insurance coverage, the Company believes that none of these claims will have a material adverse effect on the financial position, results of operations or cash flows of the Company.

See Item 1, Business - "Environmental Matters" and "Regulation", and Part II, Item 8, "Financial Statements and Supplementary Data – Note K, Commitments, Contingencies and Uncertainties - Environmental Matters 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)
2013
First Quarter	$	34.18	$	31.84	$	33.65	$	0.250
Second Quarter	38.91		32.47		35.31		0.265
Third Quarter	39.12		32.26		33.40		0.265
Fourth Quarter	36.18		32.43		35.11		0.265
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

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, 2009 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.



	12/31/2009	12/31/2010	12/31/2011	12/31/2012	12/31/2013	12/31/2014
EE	100	136	173	164	187	219
EEI Index	100	107	128	131	148	191
NYSE Composite	100	111	104	118	145	151

As of January 31, 2015, there were 2,560 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 $44.6 million in cash dividends during the twelve months ended December 31, 2014. On January 29, 2015, the Board of Directors declared a quarterly cash dividend of $0.28 per share payable on March 31, 2015 to shareholders of record on March 16, 2015. 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 ratios under Texas law. Since 1999, the Company has also returned cash to stockholders through a stock repurchase program pursuant to which the Company has bought approximately 25.4 million shares at an aggregate cost of $423.6 million, including commissions. Under the Company’s program, purchases can be made at open market prices or in private transactions and repurchased shares are available for issuance under employee benefit and stock incentive plans, or may be retired. On March 21, 2011, the Board of Directors authorized a repurchase of up to 2.5 million shares of the Company’s outstanding common stock (the "2011 Plan"). No shares of common stock were repurchased during the twelve months ended December 31, 2014 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, 2014	—	$	—	—	393,816
November 1 to November 30, 2014	—	—		—	393,816
December 1 to December 31, 2014	4,696	40.06		—	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,
	2014		2013		2012		2011		2010
Operating revenues	$	917,525	$	890,362	$	852,881	$	918,013	$	877,251
Operating income	151,163		$	165,635	$	168,658	$	190,803	$	168,962
Income before extraordinary items	$	91,428	$	88,583	$	90,846	$	103,539	$	90,317
Extraordinary gain, net of tax (a)	$	—	$	—	$	—	$	—	$	10,286
Net income	$	91,428	$	88,583	$	90,846	$	103,539	$	100,603
Basic earnings per share:
Income before extraordinary items	$	2.27	$	2.20	$	2.27	$	2.49	$	2.08
Extraordinary gain (a)	$	—	$	—	$	—	$	—	$	0.24
Net income	$	2.27	$	2.20	$	2.27	$	2.49	$	2.32
Weighted average number of shares outstanding	40,190,991		40,114,594		39,974,022		41,349,883		43,129,735
Diluted earnings per share:
Income before extraordinary items	$	2.27	$	2.20	$	2.26	$	2.48	$	2.07
Extraordinary gain (a)	$	—	$	—	$	—	$	—	$	0.24
Net income	$	2.27	$	2.20	$	2.26	$	2.48	$	2.31
Weighted average number of shares and dilutive
potential shares outstanding	40,211,717		40,126,647		40,055,581		41,587,059		43,294,419
Dividends declared per share of common stock	$	1.105	$	1.045	$	0.97	$	0.66	$	—
Cash additions to utility property, plant and equipment	$	277,078	$	237,411	$	202,387	$	178,041	$	169,966
Total assets	$	3,059,301	$	2,786,288	$	2,669,050	$	2,396,851	$	2,364,766
Long-term debt, net of current portion	$	1,134,179	$	999,620	$	999,535	$	816,497	$	849,745
Common stock equity	$	984,254	$	943,833	$	824,999	$	760,251	$	810,375

______________________


(a)	Extraordinary gain for 2010 represents a $10.3 million extraordinary gain or $0.24 earnings per share related to Texas regulatory assets.

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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"). Note A to the financial statements contains a summary of our significant accounting policies, many of which require the use of estimates and assumptions. We believe that of our significant accounting policies, the following are noteworthy because they are based on estimates and assumptions that require complex, subjective assumptions by management, which can materially impact reported results. Changes in these estimates or assumptions, or actual results that are different, could materially impact our financial condition and results of operation.

Regulatory Accounting

We apply accounting standards that recognize the economic effects of rate regulation in our Texas, New Mexico and FERC jurisdictions. As a result, we record certain costs or obligations as either assets or liabilities on our balance sheet and amortize them in subsequent periods as they are reflected in regulated rates. The deferral of costs as regulatory assets is appropriate only when the future recovery of such costs is probable. In assessing probability, we consider such factors as specific regulatory orders, regulatory precedent and the current regulatory environment. As of December 31, 2014, we had recorded regulatory assets currently subject to recovery in future rates of approximately $112.1 million and regulatory liabilities of approximately $26.1 million as discussed in greater detail in Note D of the Notes to the Financial Statements. In the event we determine that we can no longer apply the FASB guidance for regulated operations to all or a portion of our operations or to the individual regulatory assets recorded, we could be required to record a charge against income in the amount of the remaining unamortized net regulatory assets. Such an action could materially reduce our shareholders' equity.

Collection of Fuel Expense

In general, by law and regulation, our actual fuel and purchased power expenses are recovered from our customers. In times of rising fuel prices, we experience a lag in recovery of higher fuel costs. These costs are subject to reconciliation by the PUCT and the NMPRC. Prior to the completion of a reconciliation proceeding, we record fuel transactions such that fuel revenues, including fuel costs recovered through base rates in New Mexico, equal fuel expense. In the event that a disallowance of fuel cost recovery occurs during a reconciliation proceeding, the amounts recorded for fuel and purchased power expenses could differ from the amounts we are allowed to collect from our customers, and we could incur a loss to the extent of the disallowance.

Decommissioning Costs and Estimated Asset Retirement Obligation

Pursuant to the ANPP Participation Agreement and federal law, we must fund our share of the estimated costs to decommission Palo Verde Units 1, 2, 3 and associated common areas. The determination of the estimated liability requires the use of various assumptions pertaining to decommissioning costs, escalation and discount rates. We determine how we will fund our share of those estimated costs by making assumptions about future investment returns and future decommissioning cost escalations. Decommissioning costs will be adjusted prospectively for future changes in estimated decommissioning costs and when actual costs are incurred to decommission the plant. If the rates of return earned by the trusts fail to meet expectations or if estimated costs to decommission the plant increase, we could be required to increase our funding to the decommissioning trust accounts. Historically, we have been permitted to collect in rates in Texas and New Mexico the costs of nuclear decommissioning.

Future Pension and Other Post-retirement Obligations

Our obligations to retirees under various benefit plans are recorded as a liability on the balance sheets. Our liability is calculated on the basis of significant assumptions regarding discount rates, expected return on plan assets, rate of compensation increase, life expectancy of retirees and health care cost inflation. Changes in these assumptions could have a material impact on both net income and on the amount of liabilities reflected on the balance sheets.

Tax Accruals

We use the asset and liability method of accounting for income taxes. Under this method, we recognize deferred tax assets and liabilities for the future tax consequences attributable to temporary differences between the financial statement carrying

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amounts and the tax basis of existing assets and liabilities. The application of income tax law and regulations is complex and we must make judgments regarding income tax exposures. Changes in these judgments, due to changes in law, regulation, interpretation, or audit adjustments can materially affect amounts we recognize in our financial statements.

Overview

The following is an overview of our results of operations for the years ended December 31, 2014, 2013 and 2012. Net income for the years ended December 31, 2014, 2013 and 2012 is shown below:



	Years Ended December 31,
	2014		2013		2012
Net income (in thousands)	$	91,428	$	88,583	$	90,846
Basic earnings per share	2.27		2.20		2.27

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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 2014 and 2013, 2013 and 2012, and 2012 and 2011 (in thousands):



	2014				2013				2012
Prior year December 31 net income	$	88,583			$	90,846			$	103,539
Change in (net of tax):
Increased allowance for funds used during construction	6,157			(a)	895				1,737			(b)
Increased investment and interest income	5,309			(c)	1,382			(c)	(205		)
Increased (decreased) non-base revenue, net of energy expense	3,779			(d)	2,345			(e)	(5,411		)	(f)
Decreased (increased) administrative and general expense	1,536			(g)	(2,011		)	(h)	(5,643		)	(i)
Decreased retail non-fuel base revenues	(3,533		)	(j)	(2,459		)	(k)	(6,288		)	(l)
Increased taxes other than income taxes	(3,252		)	(m)	(198		)		(1,223		)	(n)
Decreased (increased) depreciation and amortization	(2,415		)	(o)	(696		)		1,804			(p)
Decreased (increased) operations and maintenance at fossil fuel generating plants	(1,792		)	(q)	751				(1,508		)	(r)
Decreased (increased) Palo Verde operations and maintenance expense	(1,635		)	(s)	964				856
Decreased (increased) customer care expense	(1,393		)	(t)	1,087			(u)	2,159			(u)
Increased interest on long-term debt (net of capitalized interest)	(390		)		(2,611		)	(v)	(248		)
Other	474				(1,712		)		1,277
Current year December 31 net income	$	91,428			$	88,583			$	90,846

______________________


(a)	Allowance for funds used during construction ("AFUDC") increased, primarily due to higher balances of construction work in progress subject to AFUDC, primarily reflecting construction work in progress on the Montana Power Station and Eastside Operations Center.


(b)	AFUDC increased, primarily due to higher balances of construction work in progress subject to AFUDC, primarily reflecting construction of Rio Grande Unit 9, which was placed in service in May 2013.


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

(d)

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.


(e)	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.


(f)	Non-base revenues, net of energy expenses decreased due to a decrease of $5.0 million in deregulated Palo Verde Unit 3 revenues and a decrease of $2.7 million in transmission wheeling revenues.


(g)	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.


(h)	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.


(i)	Administrative and general expenses increased, primarily due to increased pension and benefits expense as a result of changes in actuarial assumptions used to calculate expenses for our retiree benefit plans.

(j)

Retail non-fuel base revenues decreased, primarily due to 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; a $2.3 million decrease in sales to residential customers primarily due to milder weather; and a $1.0 million decrease in sales to large commercial and industrial customers.


(k)	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.

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(l)	Retail non-fuel base revenues decreased, primarily due to a reduction in non-fuel base rates in Texas effective May 1, 2012, and for commercial and industrial customers increased use of lower interruptible rates and decreased consumption by several large commercial and industrial customers.


(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)	Taxes other than income taxes increased, primarily due to increased revenue related taxes in Texas and increased property taxes in New Mexico.


(o)	Depreciation and amortization increased due to increased depreciable plant balances including Rio Grande Unit 9, which began commercial operation on May 13, 2013.

(p)

Depreciation and amortization decreased due to a reduction in depreciation rates for Palo Verde reflecting the approval of a license extension for Palo Verde by the NRC in April 2011, and reduced depreciation rates on gas-fired generating units and on transmission and distribution plant as a result of the Texas rate case settlement in 2012. The depreciation rate reductions were partially offset by higher depreciation expense due to an increase in depreciable plant.


(q)	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 the same period last year, and increased payroll expense.


(r)	Operations and maintenance at our fossil fuel generating plants increased primarily due to the timing of maintenance at the Newman and Rio Grande power stations in 2012.


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


(t)	Customer care expense increased primarily due to an increase in uncollectible customer accounts and an increase in payroll costs.


(u)	Customer care expense decreased primarily due to a decrease in the provision for uncollectible accounts reflecting improved collection efforts.


(v)	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.

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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 recognize 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 2014, 2013 and 2012.

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,
	2014		2013		2012
Residential	42	%	43	%	42	%
Commercial and industrial, small	34		33		34
Commercial and industrial, large	7		7		7
Sales to public authorities	17		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 76% of our non-fuel base revenues. While this customer base is more stable, it is also more sensitive to changes in weather conditions. The current rate structure in New Mexico and Texas reflects higher base rates during the peak summer season of May through October and lower base rates during November through April for our residential and small commercial and industrial customers. As a result, our business is seasonal, with higher kWh sales and revenues during the summer cooling season. The following table sets forth the percentage of our retail non-fuel base revenues derived during each quarter for the periods presented:



	Years Ended December 31,
	2014		2013		2012
January 1 to March 31	19	%	20	%	19	%
April 1 to June 30	27		27		27
July 1 to September 30	33		33		33
October 1 to December 31	21		20		21
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 2014, 2013 and 2012.



	2014	2013	2012	10-year Average
Heating degree days	1,900	2,426	2,009	2,182
Cooling degree days	2,671	2,695	2,876	2,667

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Customer growth is a key driver in the growth of retail sales. The average number of retail customers grew 1.3% in both 2014 and 2013. See the tables presented on pages 32 and 33 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 decreased by $5.4 million, or 1.0% for the twelve months ended December 31, 2014 when compared to the same period in 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 the same period last year, and were 12.9% below the 10-year average. Cooling degree days were relatively consistent with both the same period last year 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 the same period in 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.

Retail non-fuel base revenues decreased by $3.8 million, or 0.7% for the twelve months ended December 31, 2013 when compared to the same period in 2012. The decrease in retail non-fuel base revenues was primarily due to decreased revenues from our commercial and industrial customers, which reflects the impact of the reduction in non-fuel base rates for our Texas customers that became effective May 1, 2012. Non-fuel base revenues from sales to small commercial and industrial and large commercial and industrial customers decreased 1.8% and 4.3%, respectively. Retail non-fuel base revenues from sales to public authorities decreased 1.1%. While the kWh sales to public authorities increased by 0.3% in 2013 compared to 2012, revenues from this customer class reflect the impacts of energy conservation and efficiency programs and use of solar distributed generation at military installations. Additionally, 2013 revenues were negatively impacted by the federal government sequestration and shutdown in October 2013. KWh sales to small commercial and industrial customers decreased 0.7%. The decrease in retail non-fuel base revenues was partially offset by an increase of 1.1% in non-fuel base revenues from sales to residential customers reflecting a 1.2% increase in kWh sales to our residential customer class. The increase in kWh sales to our residential customers reflects a 1.3% increase in the average number of residential customers served. We experienced less favorable weather during our summer cooling season. Cooling degree days decreased 6.3%, when compared to the same period in 2012, but were higher than the 10-year average by 2.4%. Heating degree days increased 20.8% over 2012 and were 8.0% higher than the 10-year average.

Fuel revenues. Fuel revenues consist of: (i) revenues collected from customers under fuel recovery mechanisms approved by the state commissions and the FERC; (ii) deferred fuel revenues which are comprised of the difference between fuel costs and fuel revenues collected from customers; and (iii) fuel costs recovered in base rates in New Mexico. In New Mexico and with our sales for resale customer, the fuel adjustment clause allows us to recover under-recoveries or refund over-recoveries of current fuel costs above the amount recovered in base rates with a two-month lag. In Texas, fuel costs are recovered through a fixed fuel factor. We can seek to revise our fixed fuel factor based upon our approved formula at least four months after our last revision, except in the month of December. In addition, if we materially over-recover fuel costs, we must seek to refund the over-recovery, and if we materially under-recover fuel costs, we may seek a surcharge to recover those costs. Fuel over and under recoveries are considered material when they exceed 4% of the previous twelve months' fuel costs.

On July 10, 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. This amount included $3.4 million of Palo Verde performance rewards associated with the 2009 to 2012 performance periods net of disallowed fuel and purchased power costs of $1.75 million as determined by the PUCT of which $0.5 million had been reserved. The settlement provided for the reconciliation of fuel costs incurred from July 1, 2009 to March 31, 2013.

We under-recovered fuel costs by $3.1 million in the twelve months ended December 31, 2014. Included in under-recovered fuel costs is $2.2 million related to Palo Verde performance rewards, net of certain disallowed costs. In September 2014, $8.3 million was credited to customers through the applicable fuel adjustment clauses as the result of a reimbursement from the DOE related to spent nuclear fuel storage. We also under-recovered $10.8 million in fuel costs in the twelve months ended December 31, 2013, while we over-recovered fuel costs by $18.5 million in the twelve months ended December 31, 2012. A refund of $6.9 million was returned to our Texas customers in the twelve months ended December 31, 2012. At December 31, 2014, we had a net fuel under-recovery balance of $9.3 million, including an under-recovery balance of $10.3 million in Texas and FERC and an over-recovery balance of $0.9 million in New Mexico. Over-recoveries in New Mexico will be refunded through our fuel adjustment clause during 2015. Effective with May 2014 billings, we increased our Texas fixed fuel factor by 6.9% to reflect increases in prices for natural gas.

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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. Beginning April 1, 2014, we share 100% of margins on non-arbitrage sales (as defined by the settlement) and 50% of margins on arbitrage sales with our Texas customers. For the period April 1, 2014 through June 30, 2015, our total share of margins assignable to the Texas retail jurisdiction, on arbitrage and non-arbitrage off-system sales, 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 sharing 90% of off-system sales margins with our New Mexico customers, and 25% of our off-system sales margins with our resale customers under the terms of their contract.

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

The table below shows MWhs, sales revenue, fuel cost, total margins, and retained margins made on off-system sales for the twelve months ended December 31, 2014, 2013 and 2012 (in thousands except for MWhs).



	Years Ended December 31,
	2014		2013		2012
MWh sales	2,609,769		2,472,622		2,614,132
Sales revenue	$	97,980	$	82,806	$	72,770
Fuel cost	$	74,716	$	68,241	$	62,481
Total margins	$	23,264	$	14,565	$	10,289
Retained margins	$	2,147	$	1,549	$	1,098

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. Off-system sales revenues increased $10.0 million or 13.8% and the related retained margins increased $0.5 million or 41.1% for the twelve months ended December 31, 2013 when compared to the same period in 2012, as a result of higher average market prices for power partially offset by a 5.4% decline in MWh sales.

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Comparisons of kWh sales and operating revenues are shown below:



					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 $8.3 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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						Increase (Decrease)
Years Ended December 31:	2013		2012			Amount			Percent
kWh sales (in thousands):
Retail:
Residential	2,679,262		2,648,348			30,914			1.2	%
Commercial and industrial, small	2,349,148		2,366,541			(17,393		)	(0.7	)
Commercial and industrial, large	1,095,379		1,082,973			12,406			1.1
Sales to public authorities	1,622,607		1,617,606			5,001			0.3
Total retail sales	7,746,396		7,715,468			30,928			0.4
Wholesale:
Sales for resale	61,232		64,266			(3,034		)	(4.7	)
Off-system sales	2,472,622		2,614,132			(141,510		)	(5.4	)
Total wholesale sales	2,533,854		2,678,398			(144,544		)	(5.4	)
Total kWh sales	10,280,250		10,393,866			(113,616		)	(1.1	)
Operating revenues (in thousands):
Non-fuel base revenues:
Retail:
Residential	$	236,651	$	234,095		$	2,556		1.1	%
Commercial and industrial, small	184,568		188,014			(3,446		)	(1.8	)
Commercial and industrial, large	40,235		42,041			(1,806		)	(4.3	)
Sales to public authorities	95,044		96,132			(1,088		)	(1.1	)
Total retail non-fuel base revenues	556,498		560,282			(3,784		)	(0.7	)
Wholesale:
Sales for resale	2,172		2,318			(146		)	(6.3	)
Total non-fuel base revenues	558,670		562,600			(3,930		)	(0.7	)
Fuel revenues:
Recovered from customers during the period (1)	133,481		130,193			3,288			2.5
Under (over) collection of fuel	10,849		(18,539		)	29,388			—
New Mexico fuel in base rates	73,295		74,154			(859		)	(1.2	)
Total fuel revenues (2)	217,625		185,808			31,817			17.1
Off-system sales:
Fuel cost	68,241		62,481			5,760			9.2
Shared margins	13,016		9,191			3,825			41.6
Retained margins	1,549		1,098			451			41.1
Total off-system sales	82,806		72,770			10,036			13.8

Other (3)	31,261		31,703			(442		)	(1.4	)
Total operating revenues	$	890,362	$	852,881		$	37,481		4.4
Average number of retail customers (4):
Residential	347,891		343,409			4,482			1.3	%
Commercial and industrial, small	38,836		38,601			235			0.6
Commercial and industrial, large	50		50			—			—
Sales to public authorities	4,997		4,828			169			3.5
Total	391,774		386,888			4,886			1.3

_______________________


(1)	Excludes $6.9 million of refunds in 2012 related to prior periods' Texas deferred fuel revenues.


(2)	Includes deregulated Palo Verde Unit 3 revenues for the New Mexico jurisdiction of $11.4 million and $9.8 million in 2013 and 2012, respectively.


(3)	Represents revenues with no related kWh sales.


(4)	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 34% of our available net generating capacity and approximately 54% of our Company-generated energy for the twelve months ended December 31, 2014. Fluctuations in the price of natural gas, which also is the primary factor influencing the price of purchased power, have had a significant impact on our cost of energy.

Energy expenses increased $26.7 million or 9.2% for the twelve months ended December 31, 2014 compared to 2013, primarily due to an increase of $32.7 million in natural gas costs due to a 17.1% increase in the average costs of gas and a 2.4% increase in MWhs generated with natural gas, and increased total purchased power of $2.4 million due to a 17.5% increase in the average price of power purchased 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.

Energy expenses increased $37.8 million or 15.0% for the twelve months ended December 31, 2013 compared to 2012, primarily due to an increase of $36.3 million in natural gas costs due to a 24% increase in the average costs of gas and a 3.5% increase in the MWhs generated with natural gas, and increased total purchased power of $2.1 million resulting from an 18.3% increase in the average price of power purchased partially offset by a 12.5% decrease in MWh purchased.

The table below details the sources and costs of energy for 2014, 2013 and 2012.



	2014						2013
Fuel Type	Cost			MWh	Cost per MWh		Cost		MWh	Cost per MWh
	(in thousands)						(in thousands)
Natural Gas	$	196,833		3,774,209	$	52.15	$	164,139	3,686,823	$	44.52
Coal	12,883			596,252	21.61		13,680		635,717	21.52
Nuclear	41,289		(a)	5,106,668	9.76		48,949		4,966,233	9.86
Total	251,005			9,477,129	27.39		226,768		9,288,773	24.41
Purchase Power:
Photovoltaic	19,575			227,979	85.86		13,863		120,926	114.64
Other	45,229			1,162,511	39.80		48,500		1,427,004	33.99
Total purchased power	64,804			1,390,490	47.35		62,363		1,547,930	40.29
Total energy	$	315,809		10,867,619	29.94		$	289,131	10,836,703	26.68


	2012
Fuel Type	Cost			MWh	Cost per MWh
	(in thousands)
Natural Gas	$	127,833		3,561,253	$	35.90
Coal	13,604			655,108	20.77
Nuclear	49,639			5,045,772	9.84
Total	191,076			9,262,133	20.63
Purchase Power:
Photovoltaic	11,776			103,189	114.12
Other	48,475			1,665,621	29.10
Total purchased power	60,251			1,768,810	34.06
Total energy	$	251,327		11,030,943	22.78

_____________________

(a) Costs includes a DOE settlement of $8.5 million recorded in 2014. Cost per MWh excludes this settlement.

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Other operations expense

Other operations expense increased $1.7 million or 0.7% in 2014 compared to 2013 primarily due to a $5.6 million increase in other operations payroll costs including a $2.7 million increase in incentive compensation, a $1.5 million increase in customer care expenses including an increase in uncollectible customer accounts, and 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.

Other operations expense increased $0.6 million or 0.3% in 2013 compared to 2012 primarily due to increased administrative and general expense of $2.9 million due to increased outside services of $3.8 million related to software systems support and improvements and consulting and legal services related to the analysis of our future involvement at the Four Corners Generating Station. These increases were partially offset by decreased customer care expenses of $1.7 million primarily related to a decrease in our provision for uncollectible customer accounts reflecting improved collection efforts and decreased power production operation expense at Palo Verde of $1.4 million.

Maintenance expense

Maintenance expenses 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. Maintenance expenses increased $0.7 million or 1.2% in 2013 compared to 2012 due to an increase in maintenance expense for our distribution system.

Depreciation and amortization expense

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. Depreciation and amortization expense increased $1.1 million or 1.4% in 2013 compared to 2012 expense due to an increase in depreciable plant including Rio Grande Unit 9. The 2013 increase was partially offset by decreased depreciation expense due to reduced depreciation rates on gas-fired generating units and on transmission and distribution plant as a result of the Texas rate case settlement in May 2012.

Taxes other than income 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. Taxes other than income taxes increased $0.3 million or 0.5% in 2013 compared to 2012, primarily due to increased property taxes which were partially offset by a reduction in revenue related taxes.

Other income (deductions)

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 allowance for equity funds used during construction ("AEFUDC") due to higher balances of construction work in progress including the Montana Power Station and Eastside Operations Center; 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.

Other income (deductions) increased $0.2 million or 1.5% in 2013 compared to 2012, primarily as a result of increased investment and interest income, due to realized gains on equity investments in our decommissioning trusts in 2013 compared to net unrealized and realized losses on equity investments in our decommissioning trusts in 2012 and increased AEFUDC due to higher balances of construction work in progress in 2013. This increase was partially offset by increased miscellaneous deductions in 2013 due to the timing and amount of charitable donations and gains recognized on the sale of properties, plants and equipments in 2012 with no comparable amounts in 2013.

Interest charges (credits)

Interest charges (credits) decreased $0.9 million or 1.9% in 2014 compared to 2013, primarily due to increased allowance for borrowed funds used during construction, ("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.

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Interest charges (credits) increased $2.8 million or 6.2% in 2013 compared to 2012 primarily due to interest on $150 million of 3.3% Senior Notes issued in December 2012 partially offset by (i) a decrease in interest on short-term borrowings for working capital purposes; (ii) the refunding and remarketing of two series of pollution control bonds at lower rates in August 2012; and (iii) increased ABFUDC as a result of higher balances of construction work in progress in 2013.

Income tax expense

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. Income tax expense decreased by $3.3 million or 7.1% in 2013 compared to 2012 primarily due to a decrease in pre-tax income and a decrease in state income taxes due to positive developments in state income tax audits and settlements.

New accounting standards

In July 2013, the FASB issued new guidance (ASU 2013-11, Income Taxes (Topic 740)) to eliminate the diversity in the financial statement presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. ASU 2013-11 requires an entity to present an unrecognized tax benefit in the financial statements as a reduction to a deferred tax asset for a net operating loss carryforward, a similar tax loss, or a tax credit carryforward, except in certain circumstances when it would be reflected as a liability. We implemented ASU 2013-11 in the first quarter of 2014 on a prospective basis. This ASU did not have a significant impact on our statement of operations or statements of cash flows.

In May 2014, the FASB issued new guidance (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 ("IASB") 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 is effective for annual periods and interim periods within that reporting period beginning after December 15, 2016, for public business entities. Early adoption of ASU 2014-09 is not permitted. 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

In December 2014, we issued $150 million in aggregate principal amount of 5.00% Senior Notes due December 1, 2044 to fund construction expenditures and to repay the outstanding balance of our revolving credit facility ("RCF") used for working capital and general corporate purposes. We continue to maintain a strong balance of common stock equity in our capital structure which supports our bond ratings, allowing us to obtain financing from the capital markets at a reasonable cost. At December 31, 2014, our capital structure, including common stock, long-term debt, current maturities of long-term debt, and short-term borrowings under the RCF, consisted of 45.8% common stock equity and 54.2% debt. At December 31, 2014, we had on hand $40.5 million in cash and cash equivalents. Based on current projections, we believe that we will have adequate liquidity through our current cash balances, cash from operations, and available borrowings under the RCF to meet all of our anticipated cash requirements for the next twelve months. We may issue long-term debt in the capital markets to finance future capital requirements in late 2015 or early 2016.

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, taxes, and payment of our $15 million Series A 3.67% Senior Note which matures in August 2015.

Capital Requirements. During the twelve months ended December 31, 2014, 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 expand and update our transmission and distribution systems, add new generation, and make capital improvements and replacements at Palo Verde and other generating facilities. We are constructing Montana Power Station ("MPS") which will consist of four natural gas-fired 88 MW simple-cycle aeroderivative combustion turbines. Units 1 and 2 are expected to reach commercial operation during the first quarter of 2015. Units 3 and 4 are projected to be

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completed before the summer peak of 2016 and 2017, respectively. As of December 31, 2014, we had expended $234.7 million, of which $123.7 million was spent during 2014 for MPS including costs related to common facilities and transmission systems. These amounts include AFUDC. Estimated cash construction expenditures for the MPS in 2015 are approximately $100.9 million and estimated construction expenditures for all capital projects for 2015 are approximately $271.0 million. See Part I, Item 1, "Business - Construction Program". Cash capital expenditures for new electric plant were $277.1 million in the twelve months ended December 31, 2014 and $237.4 million in the twelve months ended December 31, 2013. Capital requirements for purchases of nuclear fuel were $37.9 million for the twelve months ended December 31, 2014 and $30.5 million for the twelve months ended December 31, 2013.

On December 30, 2014, we paid a quarterly cash dividend of $0.28 per share or $11.3 million to shareholders of record on December 12, 2014. We paid a total of $44.6 million in cash dividends during the twelve months ended December 31, 2014. On January 29, 2015, our Board of Directors declared a quarterly cash dividend of $0.28 per share payable on March 31, 2015 to shareholders of record on March 16, 2015 which will require cash of $11.3 million. We expect to continue paying quarterly dividends during 2015 and we expect to review the dividend policy in the second quarter of 2015. At the current payout rate, we would expect to pay total cash dividends of approximately $45.2 million during 2015. In addition, while we do not currently anticipate repurchasing shares in 2015, we may repurchase common stock in the future. Under our program, purchases can be made at open market prices or in private transactions, and repurchased shares are available for issuance under employee benefit and stock incentive plans, or may be retired. No shares of common stock were repurchased in 2014 or 2013. As of December 31, 2014, 393,816 shares remain eligible for repurchase.

We will continue to maintain a prudent level of liquidity as well as take market conditions for debt and equity securities into account. 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.

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. Income tax payments in 2015 are expected to be minimal due to tax law changes which accelerated tax deductions and alternative minimum tax credit carry-forwards.

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 and $16.9 million to our retirement plans during the twelve months ended December 31, 2014 and 2013, respectively. We did not make any contributions to our other post-retirement benefit plans during the twelve months ended December 31, 2014, as we utilized excess contributions from the $3.1 million contributed during the twelve months ended December 31, 2013. We contributed $4.5 million to our decommissioning trust funds in both 2014 and 2013. 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 Arizona Nuclear Power Project 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 million of these senior notes will mature.

Capital Resources. Cash provided by operations, $243.3 million in 2014 and $247.5 million in 2013, 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, 2014, we increased our fixed fuel factor charged to our Texas retail customers by 6.9% to reflect the increased level of prices for natural gas that existed at the time.

The Company expects 2015 earnings to be adversely impacted by the regulatory lag resulting from the commercialization of Units 1and 2 of the Montana Power Station, the related transmission system and the Eastside Operations Center expected to be

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placed in service during the first quarter of 2015. We expect to incur aggregate construction costs of approximately $260.6 million in construction of these facilities. With the introduction of these facilities into service, we will begin to incur increased expenses related to depreciation, property taxes, operations and maintenance. Furthermore, we will cease recognizing AFUDC on such facilities. Base rate increases to seek recovery of these costs are expected to be filed in the second and third quarter of 2015 for our New Mexico and Texas jurisdictions, respectively, with new rates expected to be effective in or about March 2016 for both jurisdictions.

During the twelve months ended December 31, 2014, net fuel recoveries resulted in increased cash from operations when compared to the same period in 2013. During the twelve months ended December 31, 2014, the Company had a fuel under-recovery of $3.1 million compared to an under-recovery of fuel costs of $10.8 million during the twelve months ended December 31, 2013. At December 31, 2014, we had a net fuel under-recovery balance of $9.3 million, including an under-recovery balance of $10.3 million for our Texas and FERC jurisdictions and an over-recovery balance of $0.9 million in New Mexico.

In December 2014, we issued $150 million in 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 revolving credit facility ("RCF") used for working capital and general corporate purposes.

We maintain an 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 the Company's financial statements. On January 14, 2014, we amended and extended our $300 million RCF, which includes an option to expand the size to $400 million, upon the satisfaction of certain conditions including obtaining commitments from lenders or third party financial institutions. The amended facility extends the maturity from September 2016 to January 2019. In addition, we may extend the January 2019 maturity, subject to lenders' approval, by two additional one year periods. The terms of the agreement provide that amounts we borrow under the RCF may be used for working capital and general corporate purposes. The total amount borrowed for nuclear fuel by the RGRT was $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. Borrowings by RGRT for nuclear fuel were $124.4 million at December 31, 2013, of which $14.4 million had been borrowed under the RCF and $110 million was borrowed through senior notes. 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. No borrowings were outstanding at December 31, 2014 or December 31, 2013, under the RCF for working capital and general corporate purposes.

We believe we have adequate liquidity through our current cash balances, cash from operations, available borrowings under the RCF, and our favorable access to capital markets to meet all of our anticipated cash requirements for the next twelve months. In the fourth quarter of 2013, we received approval from the NMPRC and the FERC to incrementally issue up to $300 million of long-term debt and to guarantee the issuance of up to $50 million of new long-term debt by RGRT to finance future purchases of nuclear fuel and to refinance existing nuclear fuel debt obligations. The FERC approval was effective on November 15, 2013 and terminates two years thereafter. The NMPRC approval was effective on October 30, 2013 and remains in effect until the debt is issued. The $150 million of 5.00% Senior Notes issued in December 2014 were issued pursuant to these approvals. The authorizations to issue up to an additional $150 million of long-term debt and up to $50 million of new long-term debt by RGRT provides us with the flexibility to access the debt capital markets prior to the termination of the FERC approval on November 15, 2015. Additionally, we could request approval from the FERC to issue additional debt after November 15, 2015. We may decide to issue long-term debt in the capital markets to finance capital requirements in late 2015 or early 2016.

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Contractual Obligations. Our contractual obligations as of December 31, 2014 are as follows (in thousands):



	Payments due by period
	Total		2015		2016 and 2017		2018 and 2019		2020 and Beyond
Long-Term Debt (including interest):
Senior notes (1)	$	1,870,975	$	47,700	$	95,400	$	95,400	$	1,632,475
Pollution control bonds (2)	455,420		10,583		54,259		19,918		370,660
RGRT Senior notes (3)	130,864		20,054		59,006		4,536		47,268
Financing Obligations (including interest):
Revolving credit facility (4)	14,720		14,720		—		—		—
Purchase Obligations:
Power contracts	2,563		2,563		—		—		—
Fuel contracts:
Coal (5)	17,757		11,172		6,585		—		—
Gas (5)	358,534		44,835		77,243		62,644		173,812
Nuclear fuel (6)	82,330		22,873		28,123		21,857		9,477
Retirement Plans and Other Post-retirement benefits (7)	11,319		11,319		—		—		—
Nuclear decommissioning trust funds (8)	148,101		4,535		9,071		9,071		125,424
Operating leases (9)	11,640		1,386		1,460		1,028		7,766
Total	$	3,104,223	$	191,740	$	331,147	$	214,454	$	2,366,882

_____________________

(1)

We have four issuances of Senior Notes. In May 2005, we issued $400.0 million in aggregate principal amount of 6% Senior Notes due May 15, 2035. In June 2008, we issued $150.0 million in aggregate principal amount of 7.5% Senior Notes due March 15, 2038. In December 2012, we issued $150.0 million in aggregate principal amount of 3.3% Senior Notes due December 15, 2022. In December 2014, we issued $150.0 million in aggregate principal amount of 5.00% Senior Notes due December 1, 2044.


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

(3)

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


(4)	This reflects obligations outstanding under the $300 million RCF. At December 31, 2014, $14.5 million was borrowed by RGRT for nuclear fuel. This balance includes interest based on actual interest rates at the end of 2014 and assumes this amount will be outstanding for the entire year of 2015.


(5)	Amount is based on the minimum volumes per the contract and market and/or contract price at the end of 2014. 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 2014.

(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 2015. We have no minimum cash contractual funding requirement related to our retirement income plan or other post-retirement benefits for 2015. However, we may decide to fund at higher levels and expect to contribute $11.3 million to our retirement plans in 2015, as disclosed in Part II, Item 8, "Notes to Financial Statements, Note M, Employee Benefits". Minimum funding requirements for 2015 and beyond are not included due to the uncertainty of interest rates and the related return on assets.


(8)	These obligations represent funding amounts approved in PUCT Docket No. 40094 and NMPRC Case No. 09-00171-UT.


(9)	We lease land in El Paso adjacent to the Newman Power Station under a lease which expires in June 2033 with a renewal option of 25 years. In addition, we lease certain warehouse facilities in El Paso under a lease which expires in December 2015. We also have several other leases for office, parking facilities and equipment which expire within the next three years.

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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.

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 $104.7 million and $85.3 million as of December 31, 2014 and 2013, respectively. A hypothetical 10% increase in interest rates would reduce the fair values of these funds by $1.2 million on their fair values at both December 31, 2014 and 2013.

Equity Price Risk

Our decommissioning trust funds include marketable equity securities of approximately $123.4 million and $122.9 million at December 31, 2014 and 2013, respectively. A hypothetical 20% decrease in equity prices would reduce the fair values of these funds by $24.7 million and $24.6 million based on their fair values at December 31, 2014 and 2013, respectively. Declines in market prices could require that additional amounts be contributed to our nuclear decommissioning trusts to maintain minimum funding requirements. We will not have a requirement to expend monies held in trust before 2044 or a later period when we begin to decommission Palo Verde.

Commodity Price Risk

We utilize contracts of various durations for the purchase of natural gas, uranium concentrates and coal to effectively manage our available fuel portfolio. These agreements contain variable pricing provisions and are settled by physical delivery. The fuel contracts with variable pricing provisions, as well as substantially all of our purchased power requirements, are exposed to fluctuations in prices due to unpredictable factors, including weather and various other worldwide events, which impact supply and demand. However, our exposure to fuel and purchased power price risk is substantially mitigated through the operation of the PUCT and NMPRC rules and our fuel clauses, as discussed previously.

In the normal course of business, we enter into contracts of various durations for the forward sales and purchases of electricity to effectively manage our available generating capacity and supply needs. Such contracts include forward contracts for the sale of generating capacity and energy during periods when our available power resources are expected to exceed the requirements of our retail native load and sales for resale. We also enter into forward contracts for the purchase of wholesale capacity and energy during periods when the market price of electricity is below our expected incremental power production costs or to supplement our generating capacity when demand is anticipated to exceed such capacity. As of January 31, 2015, we had entered into forward sales and purchase contracts for energy as discussed in Part I, Item 1, "Business – Energy Sources – Purchased Power." These agreements are generally fixed-priced contracts which qualify for the "normal purchases and normal sales" exception provided in FASB guidance for accounting for derivative instruments and hedging activities and are not recorded at their fair value in our financial statements. Because of the operation of the PUCT and the NMPRC rules and our fuel clauses, these contracts do not expose us to significant commodity price risk.

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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, 2014. 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, 2014, 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 44 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	44

Balance Sheets as of December 31, 2014 and 2013	45

Statements of Operations for the years ended December 31, 2014, 2013 and 2012	47

Statements of Comprehensive Operations for the years ended December 31, 2014, 2013 and 2012	48

Statements of Changes in Common Stock Equity for the years ended December 31, 2014, 2013 and 2012	49

Statements of Cash Flows for the years ended December 31, 2014, 2013 and 2012	50

Notes to Financial Statements	51

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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 as of December 31, 2014 and 2013, 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, 2014. We also have audited El Paso Electric Company’s internal control over financial reporting as of December 31, 2014, 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, 2014 and 2013, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2014, 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, 2014, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

/s/ KPMG LLP

Kansas City, Missouri

February 27, 2015

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EL PASO ELECTRIC COMPANY

BALANCE SHEETS



ASSETS (In thousands)	December 31,
	2014			2013
Utility plant:
Electric plant in service	$	3,229,255		$	3,076,549
Less accumulated depreciation and amortization	(1,266,672		)	(1,214,088		)
Net plant in service	1,962,583			1,862,461
Construction work in progress	414,284			282,647
Nuclear fuel; includes fuel in process of $46,996 and $48,492, respectively	185,185			188,185
Less accumulated amortization	(73,701		)	(75,820		)
Net nuclear fuel	111,484			112,365
Net utility plant	2,488,351			2,257,473
Current assets:
Cash and cash equivalents	40,504			25,592
Accounts receivable, principally trade, net of allowance for doubtful accounts of $2,253 and $2,261, respectively	71,165			65,350
Accumulated deferred income taxes	13,957			26,965
Inventories, at cost	45,889			45,942
Under-collection of fuel revenues	10,253			7,248
Prepayments and other	12,213			7,694
Total current assets	193,981			178,791
Deferred charges and other assets:
Decommissioning trust funds	234,286			214,095
Regulatory assets	112,086			101,050
Other	30,597			34,879
Total deferred charges and other assets	376,969			350,024
Total assets	$	3,059,301		$	2,786,288

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,
	2014			2013
Capitalization:
Common stock, stated value $1 per share, 100,000,000 shares authorized, 65,725,246 and 65,639,091 shares issued, and 124,297 and 120,534 restricted shares, respectively	$	65,850		$	65,760
Capital in excess of stated value	318,515			314,443
Retained earnings	1,032,537			985,665
Accumulated other comprehensive income (loss), net of tax	(8,001		)	2,612
	1,408,901			1,368,480
Treasury stock, 25,492,919 shares at cost	(424,647		)	(424,647		)
Common stock equity	984,254			943,833
Long-term debt, net of current portion	1,134,179			999,620
Total capitalization	2,118,433			1,943,453
Current liabilities:
Current maturities of long-term debt	15,000			—
Short-term borrowings under the revolving credit facility	14,532			14,352
Accounts payable, principally trade	78,862			61,795
Taxes accrued	28,210			25,206
Interest accrued	12,758			12,189
Over-collection of fuel revenues	932			1,048
Other	24,715			22,932
Total current liabilities	175,009			137,522
Deferred credits and other liabilities:
Accumulated deferred income taxes	474,154			449,925
Accrued pension liability	94,272			84,012
Accrued post-retirement benefit liability	59,342			50,655
Asset retirement obligation	74,577			65,214
Regulatory liabilities	26,099			26,416
Other	37,415			29,091
Total deferred credits and other liabilities	765,859			705,313
Commitments and contingencies
Total capitalization and liabilities	$	3,059,301		$	2,786,288

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,
	2014			2013			2012
Operating revenues	$	917,525		$	890,362		$	852,881
Energy expenses:
Fuel	251,005			226,768			191,076
Purchased and interchanged power	64,804			62,363			60,251
	315,809			289,131			251,327
Operating revenues net of energy expenses	601,716			601,231			601,554
Other operating expenses:
Other operations	238,832			237,155			236,558
Maintenance	65,629			61,068			60,339
Depreciation and amortization	83,342			79,626			78,556
Taxes other than income taxes	62,750			57,747			57,443
	450,553			435,596			432,896
Operating income	151,163			165,635			168,658
Other income (deductions):
Allowance for equity funds used during construction	14,662			10,008			9,427
Investment and interest income, net	13,633			7,033			5,275
Miscellaneous non-operating income	4,075			909			1,415
Miscellaneous non-operating deductions	(4,199		)	(3,635		)	(2,013		)
	28,171			14,315			14,104
Interest charges (credits):
Interest on long-term debt and revolving credit facility	59,028			58,635			54,632
Other interest	1,250			431			1,190
Capitalized interest	(5,092		)	(5,299		)	(5,312		)
Allowance for borrowed funds used during construction	(8,368		)	(6,055		)	(5,573		)
	46,818			47,712			44,937
Income before income taxes	132,516			132,238			137,825
Income tax expense	41,088			43,655			46,979
Net income	$	91,428		$	88,583		$	90,846

Basic earnings per share	$	2.27		$	2.20		$	2.27

Diluted earnings per share	$	2.27		$	2.20		$	2.26

Dividends declared per share of common stock	$	1.105		$	1.045		$	0.97
Weighted average number of shares outstanding	40,190,991			40,114,594			39,974,022
Weighted average number of shares and dilutive potential shares outstanding	40,211,717			40,126,647			40,055,581

See accompanying notes to financial statements.

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EL PASO ELECTRIC COMPANY

STATEMENTS OF COMPREHENSIVE OPERATIONS

(In thousands)



	Years Ended December 31,
	2014			2013			2012
Net income	$	91,428		$	88,583		$	90,846
Other comprehensive income (loss):
Unrecognized pension and post-retirement benefit costs:
Net gain (loss) arising during period	(54,328		)	82,964			(2,109		)
Prior service benefit	34,200			97			—
Reclassification adjustments included in net income for amortization of:
Prior service benefit	(7,659		)	(5,560		)	(5,762		)
Net loss	6,182			10,472			11,971
Net unrealized gains/losses on marketable securities:
Net holding gains arising during period	10,827			17,699			9,927
Reclassification adjustments for net (gains) losses included in net income	(7,350		)	(553		)	1,042
Net losses on cash flow hedges:
Reclassification adjustment for interest expense included in net income	438			411			385
Total other comprehensive income (loss) before income taxes	(17,690		)	105,530			15,454
Income tax benefit (expense) related to items of other comprehensive income (loss):
Unrecognized pension and post-retirement benefit costs	8,051			(33,566		)	(1,464		)
Net unrealized gains on marketable securities	(760		)	(3,100		)	(2,438		)
Losses on cash flow hedges	(214		)	(168		)	(131		)
Total income tax benefit (expense)	7,077			(36,834		)	(4,033		)
Other comprehensive income (loss), net of tax	(10,613		)	68,696			11,421
Comprehensive income	$	80,815		$	157,279		$	102,267

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, 2011	65,452,073		$	65,452		$	309,777		$	887,174		$	(77,505	)	25,492,919	$	(424,647	)	$	760,251
Restricted common stock grants and deferred compensation	87,428		87			1,691													1,778
Performance share awards vested	174,038		174			1,019													1,193
Stock awards withheld for taxes	(52,778	)	(52		)	(1,770		)											(1,822		)
Forfeited restricted common stock	(88,100	)	(88		)	(1,206		)											(1,294		)
Deferred taxes on stock incentive plan						1,101													1,101
Stock options exercised	32,336		32			382													414
Net income									90,846										90,846
Other comprehensive income												11,421							11,421
Dividends declared									(38,889		)								(38,889		)
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												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												(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

See accompanying notes to financial statements.

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EL PASO ELECTRIC COMPANY

STATEMENTS OF CASH FLOWS

(In thousands)



	Years Ended December 31,
	2014			2013			2012
Cash Flows From Operating Activities:
Net income	$	91,428		$	88,583		$	90,846
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization of electric plant in service	83,342			79,626			78,556
Amortization of nuclear fuel	43,864			42,537			42,953
Deferred income taxes, net	39,129			44,678			43,561
Allowance for equity funds used during construction	(14,662		)	(10,008		)	(9,427		)
Other amortization and accretion	18,380			16,556			14,724
Gain on sale of property, plant and equipment	(2,092		)	(112		)	(1,346		)
Net (gains) losses on sale of decommissioning trust funds	(7,350		)	(553		)	1,042
Other operating activities	(93		)	(260		)	(175		)
Change in:
Accounts receivable	(5,815		)	(2,450		)	13,448
Inventories	(786		)	(3,673		)	(1,926		)
Net over-collection (under-collection) of fuel revenues	(3,121		)	(10,843		)	11,668
Prepayments and other	(2,750		)	(4,295		)	(2,784		)
Accounts payable	9,684			8,180			1,725
Taxes accrued	(2,209		)	(627		)	(3,054		)
Other current liabilities	1,198			958			78
Deferred charges and credits	(4,807		)	(822		)	(6,781		)
Net cash provided by operating activities	243,340			247,475			273,108
Cash Flows From Investing Activities:
Cash additions to utility property, plant and equipment	(277,078		)	(237,411		)	(202,387		)
Cash additions to nuclear fuel	(37,877		)	(30,535		)	(46,009		)
Capitalized interest and AFUDC:
Utility property, plant and equipment	(23,030		)	(16,063		)	(15,000		)
Nuclear fuel	(5,092		)	(5,299		)	(5,312		)
Allowance for equity funds used during construction	14,662			10,008			9,427
Decommissioning trust funds:
Purchases, including funding of $4.5 million	(117,675		)	(65,491		)	(107,705		)
Sales and maturities	108,311			56,148			98,542
Proceeds from sale of property, plant and equipment	2,395			112			1,757
Other investing activities	4,192			5,767			633
Net cash used for investing activities	(331,192		)	(282,764		)	(266,054		)
Cash Flows From Financing Activities:
Dividends paid	(44,556		)	(42,049		)	(38,889		)
Borrowings under the revolving credit facility:
Proceeds	231,399			44,883			234,575
Payments	(231,219		)	(52,686		)	(245,799		)
Pollution control bonds:
Proceeds	—			—			92,535
Payments	—			—			(92,535		)
Proceeds from issuance of senior notes	149,468			—			149,682
Other financing activities	(2,328		)	(324		)	(3,774		)
Net cash provided by (used for) financing activities	102,764			(50,176		)	95,795
Net increase (decrease) in cash and cash equivalents	14,912			(85,465		)	102,849
Cash and cash equivalents at beginning of period	25,592			111,057			8,208
Cash and cash equivalents at end of period	$	40,504		$	25,592		$	111,057

See accompanying notes to financial statements.

Table of Contents

INDEX TO NOTES TO FINANCIAL STATEMENTS



	Page
Note A. Summary of Significant Accounting Policies	52

Note B. New Accounting Standards	55

Note C. Regulation	55

Note D. Regulatory Assets and Liabilities	58

Note E. Utility Plant, Palo Verde and Other Jointly-Owned Utility Plant	59

Note F. Accounting for Asset Retirement Obligations	63

Note G. Common Stock	64

Note H. Accumulated Other Comprehensive Loss	69

Note I. Long-Term Debt and Financing Obligations	71

Note J. Income Taxes	73

Note K. Commitments, Contingencies and Uncertainties	76

Note L. Litigation	79

Note M. Employee Benefits	80

Note N. Franchises and Significant Customers	91

Note O. Financial Instruments and Investments	93

Note P. Supplemental Statements of Cash Flow Disclosures	98

Note Q. Selected Quarterly Financial Data (Unaudited)	99

Table of Contents

EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

A. Summary of Significant Accounting Policies

General. El Paso Electric Company is a public utility engaged in the generation, transmission and distribution of electricity in an area of approximately 10,000 square miles in west Texas and southern New Mexico. 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. Actual results could differ from those estimates.

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

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

Utility Plant. Utility plant is generally reported at cost. The cost of renewals and betterments are capitalized and the costs of repairs and minor replacements are charged to the appropriate operating expense accounts. Depreciation is provided on a straight-line basis over the estimated remaining lives of the assets (ranging in average from 5 to 48 years). The average composite depreciation rate utilized in 2014, 2013 and 2012 was 2.60%, 2.61%, and 2.64%, respectively. When property subject to composite depreciation is retired or otherwise disposed of in the normal course of business, its cost – together with the cost of removal, less salvage – is charged to accumulated depreciation. For other property dispositions, the applicable cost and accumulated depreciation is removed from the balance sheet accounts and a gain or loss is recognized.

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

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

AFUDC and Capitalized Interest. The Company capitalizes interest ("ABFUDC") and common equity ("AEFUDC") costs to construction work in progress and capitalizes interest to nuclear fuel in process in accordance with the FERC Uniform System of Accounts as provided for in FASB guidance. AFUDC is a non-cash component of income and is calculated monthly and charged to all new eligible construction and capital improvement projects. AFUDC is compounded on a semi-annual basis. The AFUDC rates used in 2014, 2013 and 2012 were 8.15%, 8.10% and 8.53%, respectively.

Asset Retirement Obligation. FASB guidance sets forth accounting requirements for the recognition and measurement of liabilities associated with the retirement of tangible long-lived assets. An asset retirement obligation ("ARO") associated with long-lived assets included within the scope of FASB guidance is that for which a legal obligation exists under enacted laws, statutes, written or oral contracts, including obligations arising under the doctrine of promissory estoppel and legal obligations to perform an asset retirement activity even if the timing and/or settlement are conditioned on a future event that may or may not be within

Table of Contents

EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

the control of an entity. See Note F. Under FASB guidance, these liabilities are recognized as incurred if a reasonable estimate of fair value can be established and are capitalized as part of the cost of the related tangible long-lived assets. The Company records the increase in the ARO due to the passage of time as an operating expense (accretion expense).

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

Investments. The Company’s marketable securities, included in decommissioning trust funds in the balance sheets, are reported at fair value and consist of cash, equity securities and municipal, federal and corporate bonds in trust funds established for decommissioning of its interest in Palo Verde. Such marketable securities are classified as "available-for-sale" securities and, as such, unrealized gains and losses are included in accumulated other comprehensive loss as a separate component of common stock equity. However, if declines in fair value of marketable securities below original cost basis are determined to be other than temporary, then the declines are reported as losses in the statement of operations and a new cost basis is established for the affected securities at fair value. Gains and losses are determined using the cost of the security based on the specific identification basis. See Note O.

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

Inventories. Inventories, primarily parts, materials, supplies, fuel oil and natural gas are stated at average cost not to exceed recoverable cost.

Operating Revenues Net of Energy Expenses. The Company accrues revenues for services rendered, including unbilled electric service revenues. Energy expenses are stated at actual cost incurred. The Company’s Texas retail customers are billed under base rates and a fixed fuel factor approved by the Public Utility Commission of Texas ("PUCT"). The Company’s New Mexico retail customers 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 Note C.

Revenues. Revenues related to the sale of electricity are generally recorded when service is rendered or electricity is delivered to customers. The billing of electricity sales to retail customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. Unbilled revenues are estimated based on monthly generation volumes and by applying an average revenue/kWh to the number of estimated kWhs delivered but not billed. Accounts receivable included accrued unbilled revenues of $21.2 million and $19.8 million at December 31, 2014 and 2013, 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 2014, 2013 and 2012 are as follows (in thousands):



	2014		2013		2012
Balance at beginning of year	$	2,261	$	2,906	$	3,015
Additions:
Charged to costs and expense	2,755		2,098		3,087
Recovery of previous write-offs	1,516		1,929		2,041
Uncollectible receivables written off	4,279		4,672		5,237
Balance at end of year	$	2,253	$	2,261	$	2,906

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EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

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

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

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

Pension and Post-retirement Benefit Accounting. See Note M for a discussion of the Company’s accounting policies for its employee benefits.

Reclassification. Certain amounts in the financial statements for 2013 and 2012 have been reclassified to conform with the 2014 presentation.

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EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

B. New Accounting Standards

In July 2013, the FASB issued new guidance (Accounting Standards Update ("ASU") 2013-11, Income Taxes (Topic 740)) to eliminate the diversity in the financial statement presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. ASU 2013-11 requires an entity to present an unrecognized tax benefit in the financial statements as a reduction to a deferred tax asset for a net operating loss carryforward, a similar tax loss, or a tax credit carryforward, except in certain circumstances when it would be reflected as a liability. The Company implemented ASU 2013-11 in the first quarter of 2014 on a prospective basis. This ASU did not have a significant impact on the Company's statement of operations or statements of cash flows.

In May 2014, the FASB issued new guidance (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 ("IASB") 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 is effective for annual periods and interim periods within that reporting period beginning after December 15, 2016, for public business entities. Early adoption of ASU 2014-09 is not permitted. The Company is currently assessing the future impact of this ASU.

C. Regulation

General

Texas Regulatory Matters

Table of Contents

EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

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.

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 twelve months ended December 31, 2014 financial results include a $2.1 million, pre-tax increase to income reflecting the settlement of the Texas fuel reconciliation proceeding. The settlement included the recognition of $3.4 million of Palo Verde performance rewards associated with the 2009 to 2012 performance periods net of disallowed fuel and purchased power costs of $1.75 million of which $0.5 million had been previously reserved. Palo Verde performance rewards are not recognized in the Company’s financial results until the PUCT has ordered a final determination in a fuel proceeding or comparable evidence of collectability is obtained. In addition, the Company reimbursed the City of El Paso approximately $0.1 million in incurred expenses. The settlement also provides that 100% of margins on non-arbitrage off-system sales (as defined by the settlement) and 50% of margins on arbitrage off-system sales be shared with its Texas customers beginning April 1, 2014. For the period April 1, 2014 through June 30, 2015, the Company’s total share of margins assignable to 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. The Company also agreed to file with the PUCT a proceeding to address the reasonableness of the Company’s decision to not continue to participate in the Four Corners coal-fired generating Units 4 and 5 after July 2016. It is expected that issues related to the final coal mine closing and reclamation costs will be addressed in that proceeding as well as other issues related to post-participation events such as the asset retirement obligations of the Company related to those two units. The PUCT’s final order completes the regulatory review and reconciliation of the Company’s fuel expenses for the period through March 31, 2013.

Montana Power Station Approvals. As discussed further below, the Company has received a Certificate of Convenience and Necessity ("CCN") from the PUCT to construct all four units of the Montana Power Station ("the MPS") in El Paso County, Texas. The Company also obtained air permits from the Texas Commission on Environmental Quality ("TCEQ") and the U.S. Environmental Protection Agency ("EPA").

On June 23, 2014, the U.S. Supreme Court issued an opinion in the Utility Air Regulatory Group vs EPA regarding EPA’s authority to require greenhouse gas emissions ("GHG") Prevention of Significant Deterioration (“PSD”) permits for stationary sources. The opinion concluded that the EPA erred in making applicability of the Clean Air Act (“CAA”) permitting requirements based on GHG emissions. As a result, the Company believes its EPA air permit is no longer required and could be rescinded, and it is eligible for a standard air permit to replace the new source review permit issued by the TCEQ. Accordingly, on August 1, 2014, the Company submitted a request to the EPA to rescind the EPA air permit which request remains pending. Also, on September 16, 2014, the Company applied for a standard air permit, which TCEQ issued on October 2, 2014.

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EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

In 2013, the Company filed three transmission line CCN applications with the PUCT as part of the MPS Project:


•	MPS to Caliente: a 115-kV transmission line from the MPS to the existing Caliente Substation in east El Paso. (PUCT Docket No. 41360)


•	MPS In & Out: a 115-kV transmission line from the MPS to intersect with the existing Caliente - Coyote 115-kV transmission line. (PUCT Docket No. 41359)


•	MPS to Montwood: a 115-kV transmission line from the MPS to the existing Montwood Substation in east El Paso. (PUCT Docket No. 41809)

New Mexico Regulatory Matters

Federal Regulatory Matters

Table of Contents

EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

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

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

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

Sales for Resale

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, 2014		December 31, 2013
Regulatory assets
Regulatory tax assets (a)	(b)	$	66,134	$	61,772
Loss on reacquired debt (c)	May 2035	17,486		18,338
Final coal reclamation (d)	(e)	10,702		4,290
Nuclear fuel postload daily financing charge	(d)	4,127		4,141
Unrecovered issuance costs due to reissuance of PCBs (c)	August 2042	860		893
Texas energy efficiency	(f)	1,817		—
Texas 2012 rate case costs	April 2014	—		581
Texas 2015 rate case costs	(g)	169		—
Texas military base discount and recovery factor	(h)	—		759
New Mexico procurement plan costs	(g)	139		139
New Mexico renewable energy credits	(g)	5,456		4,833
New Mexico 2010 FPPCAC audit	(g)	434		433
New Mexico Palo Verde deferred depreciation	(b)	4,720		4,871
New Mexico 2015 rate case costs	(g)	42		—
Total regulatory assets		$	112,086	$	101,050
Regulatory liabilities
Regulatory tax liabilities (a)	(b)	$	17,252	$	17,752
Accumulated deferred investment tax credit (i)	(b)	4,334		4,656
New Mexico energy efficiency	(f)	3,904		3,646
Texas energy efficiency	(f)	—		362
Texas military base discount and recovery factor	(h)	609		—
Total regulatory liabilities		$	26,099	$	26,416

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________________


(a)	No specific return on investment is required since related assets and liabilities offset.


(b)	The amortization period for this asset is based upon the life of the associated assets or liabilities.


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


(d)	This item is recovered through fuel recovery mechanisms.


(e)	This item and the related final coal reclamation liability have been included or will be requested in rate base.


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


(i)	This item is excluded from rate base.

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

The table below presents the balance of each major class of depreciable assets at December 31, 2014 (in thousands):



	Gross Plant		Accumulated Depreciation			Net Plant
Nuclear production	$	874,817	$	(286,585	)	$	588,232
Steam and other	684,863		(284,764		)	400,099
Total production	1,559,680		(571,349		)	988,331
Transmission	433,982		(250,941		)	183,041
Distribution	1,020,901		(342,931		)	677,970
General	139,491		(56,412		)	83,079
Intangible	75,201		(45,039		)	30,162
Total	$	3,229,255	$	(1,266,672	)	$	1,962,583

Amortization of intangible plant (software) is provided on a straight-line basis over the estimated useful life of the asset (ranging from 5 to 10 years). The table below presents the actual and estimated amortization expense for intangible plant for the previous three years and for the next five years (in thousands):



2012	7,183
2013	7,683
2014	8,051
2015 (estimated)	7,505
2016 (estimated)	7,030
2017 (estimated)	6,388
2018 (estimated)	4,762
2019 (estimated)	3,101

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

Other jointly-owned utility plant includes a 7% interest in Units 4 and 5 at Four Corners Generating Station ("Four Corners") and certain other transmission facilities. A summary of the Company’s investment in jointly-owned utility plant, excluding fuel inventories, at December 31, 2014 and 2013 is as follows (in thousands):

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	December 31, 2014						December 31, 2013
	Palo Verde			Other			Palo Verde			Other
Electric plant in service	$	874,817		$	219,318		$	817,665		$	217,137
Accumulated depreciation	(286,585		)	(176,492		)	(271,173		)	(173,819		)
Construction work in progress	55,632			6,900			75,040			2,347
Total	$	643,864		$	49,726		$	621,532		$	45,665

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.

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.

Decommissioning. Pursuant to the ANPP Participation Agreement and federal law, the Company must fund its share of the estimated costs to decommission Palo Verde Units 1, 2 and 3, including the Common Facilities, through the term of their respective operating licenses and is required to maintain a minimum accumulation and funding level in its decommissioning account at the end of each annual reporting period during the life of the plant. The Company has established external trusts with an independent trustee, which enables the Company to record a current deduction for federal income tax purposes for most of the amounts funded. At December 31, 2014, the Company’s decommissioning trust fund had a balance of $234.3 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 asset retirement obligation 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.

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 participant owners of Palo Verde, 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

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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 owners 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 participant owners of Palo Verde, 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 total submitted claim amount was $42.5 million, of which the Company's portion is $6.7 million. The reimbursement is anticipated to be received in the first half of 2015, and the majority will be refunded to customers through the applicable fuel adjustment clauses.

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

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

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NOTES TO FINANCIAL STATEMENTS

power plant licenses and renewals that went into effect when the D.C. Circuit issued its June 2012 decision. The August 24 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.

Liability and Insurance Matters. The Palo Verde Participants have insurance for public liability resulting from nuclear energy hazards to the full limit of liability under federal law, which is currently at $13.6 billion. This potential liability is covered by primary liability insurance provided by commercial insurance carriers in the amount of $375 million, and the balance is covered by an industry-wide retrospective assessment program. If a loss at a nuclear power plant covered by the programs exceeds the accumulated funds in the primary level of protection, the Company could be assessed retrospective premium adjustments on a per incident basis. Under federal law, the maximum assessment per reactor under the program for each nuclear incident is approximately $127.3 million, subject to an annual limit of $19.0 million. Based upon the Company's 15.8% interest in the three Palo Verde units, the Company's maximum potential assessment per incident for all three units is approximately $60.4 million, with an annual payment limitation of approximately $9.0 million.

The Palo Verde Participants maintain $2.8 billion of "all risk" nuclear property insurance. The insurance provides coverage for property damage and decontamination at Palo Verde. For covered incidents involving property damage not accompanied by a release of radioactive material, the policy's coverage limit is $2.3 billion. The Company has also secured insurance against portions of any increased cost of generation or purchased power and business interruption resulting from a sudden and unforeseen outage of any of the three units. The insurance coverage discussed in this and the previous paragraph is subject to certain policy conditions and exclusions. A mutual insurance company whose members are utilities with nuclear facilities issues these policies.

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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 $10.9 million for the current policy period.

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 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 “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, which is expected to occur not later than July 2016, subject to the receipt of regulatory approvals. 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, 2014 are obligations of $6.1 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.

F. Accounting for Asset Retirement Obligations

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

The ARO liability for Palo Verde is based upon the estimated cost of decommissioning the plant from the 2013 Palo Verde decommissioning study. See Note E. The ARO liability is calculated by adjusting the estimated decommissioning costs for spent fuel storage and a profit margin and market-risk premium factor. The resulting costs are escalated over the remaining life of the plant and finally discounted using a credit-risk adjusted discount rate. As Palo Verde approaches the end of its estimated useful life, the difference between the ARO liability and future current cost estimates will narrow over time due to the accretion of the ARO liability. Because the DOE is obligated to assume responsibility for the permanent disposal of spent fuel, spent fuel costs have not been included in the ARO calculation. The Company maintains six external trust funds with an independent trustee that are legally restricted to settling its ARO at Palo Verde. The fair value of the funds at December 31, 2014 is $234.3 million.

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



	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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A roll forward of the Company’s total ARO liability from January 1, 2012 through December 31, 2014, 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. In 2012, the estimate revision includes a change to the probability of extending Four Corners’ operating term.



	2014		2013			2012
ARO liability at beginning of year	$	65,214	$	62,784		$	56,140
Liabilities incurred	—		—			—
Liabilities settled	—		(36		)	(450		)
Revisions to estimate	3,561		(3,401		)	1,929
Accretion expense	5,802		5,867			5,165
ARO liability at end of year	$	74,577	$	65,214		$	62,784

The Company has transmission and distribution lines which are operated under various property easement agreements. If the easements were to be released, the Company may have a legal obligation to remove the lines; however, the Company has assessed the likelihood of this occurring as remote. The majority of these easements include renewal options which the Company routinely exercises.

G. Common Stock

Overview

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

Long-Term Incentive Plan

On May 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 common stock for the benefit of directors and employees. Under the Amended and Restated 2007 LTIP, common stock may be issued through the award or grant of non-statutory stock options, incentive stock options, stock appreciation rights, restricted stock, bonus stock, performance stock, cash-based awards and other stock-based awards. The Company may issue new shares, purchase shares on the open market, or issue shares from shares the Company has repurchased to meet the share requirements of the Amended and Restated 2007 LTIP. As discussed in Note A, the Company accounts for its stock-based long-term incentive plan under FASB guidance for stock-based compensation.

Stock Options. Stock options have been granted at exercise prices equal to or greater than the market value of the underlying shares at the date of grant. The fair value for these options was estimated at the grant date using the Black-Scholes option pricing model. The options expired ten years from the date of grant unless terminated earlier by the Board of Directors (the “Board”). Stock options have not been granted since 2003.

The 15,000 options outstanding at December 31, 2012 were exercised during 2013 with a weighted average exercise price of $12.78. The Company received $0.2 million in cash and realized a current tax benefit of $0.1 million. The Company had no stock options outstanding as of December 31, 2013 and December 31, 2014.

The intrinsic value of stock options exercised in 2013 and 2012 were $0.3 million and $0.6 million, respectively. No options were forfeited, vested or expired during 2014, 2013 and 2012. No compensation cost was recognized in 2014, 2013 and 2012 for stock options.

Restricted Stock 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.

The expense, deferred tax benefit, and current tax expense recognized related to restricted stock awards and other stock-based awards in 2014, 2013 and 2012 is presented below (in thousands):



	2014		2013		2012

Expense (a)	$	3,471	$	2,458	$	1,508
Deferred tax benefit	1,215		860		528
Current tax benefit recognized	39		109		94

_____________________

(a) Any capitalized costs related to these expenses is less than $0.1 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 2014, 2013 and 2012 is presented below (in thousands):



	2014		2013		2012

Aggregated intrinsic value	$	3,441	$	2,077	$	2,242
Fair value at grant date	3,330		1,765		1,973

The unvested restricted stock and other stock-based award transactions for 2014 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, 2013	120,534		$	35.19
Stock awards	113,776		36.95
Vested	(90,851	)	36.66
Forfeitures	(19,162	)	34.72
Restricted shares outstanding at December 31, 2014	124,297		35.81		$	1,662	$	4,979

_______________________

(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 2014, 2013 and 2012 were:



	2014		2013		2012
Weighted average fair value per share	$	36.95	$	35.48	$	32.45

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

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NOTES TO FINANCIAL STATEMENTS

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)
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
January 1, 2012	175.0	%	174,038	1,193		2009-2011	6,029

In 2015, 2016 and 2017, subject to meeting certain performance criteria, additional performance shares could be awarded. In accordance with FASB guidance related to stock-based compensation, the Company recognizes the related compensation expense by ratably amortizing the grant date fair value of awards over the requisite service period and the compensation expense is only adjusted for forfeitures. The actual number of shares to be issued can range from zero to 145,496 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, 2013	124,997		$	31.38
Performance share awards	37,561		26.36
Performance shares lapsed	(34,050	)	28.03
Performance shares forfeited	(7,027	)	32.24
Performance shares outstanding at December 31, 2014	121,481		30.71		$	975	$	4,867

_______________________

(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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NOTES TO FINANCIAL STATEMENTS

A summary of information related to performance shares for 2014, 2013 and 2012 is presented below:



	2014		2013		2012
Weighted average per share grant date fair value per share of performance shares awarded	$	26.36	$	34.69	$	32.74
Fair value of performance shares vested (in thousands)	—		849		1,193
Intrinsic value of performance shares vested (in thousands) (a)	—		1,450		3,464
Compensation expense (in thousands) (b)	1,181		1,188		170
Deferred tax benefit related to compensation expense (in thousands)	413		416		59

_____________________

(a) Based on a 100% performance level.

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

Repurchase Program

No shares of common stock were repurchased during the twelve months ended December 31, 2014. 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.

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

Dividend Policy

On December 30, 2014, the Company paid $11.3 million in quarterly cash dividends to shareholders. The Company paid a total of $44.6 million, $42.0 million and $38.9 million in cash dividends during the twelve months ended December 31, 2014, 2013 and 2012, respectively. On January 29, 2015, the Board of Directors declared a quarterly cash dividend of $0.28 per share payable on March 31, 2015 to shareholders of record on March 16, 2015.

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NOTES TO FINANCIAL STATEMENTS

Basic and Diluted Earnings Per Share

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



	Years Ended December 31,
	2014			2013			2012
Weighted average number of common shares outstanding:
Basic number of common shares outstanding	40,190,991			40,114,594			39,974,022
Dilutive effect of unvested performance awards	20,726			12,053			66,756
Dilutive effect of stock options	—			—			14,803
Diluted number of common shares outstanding	40,211,717			40,126,647			40,055,581
Basic net income per common share:
Net income	$	91,428		$	88,583		$	90,846
Income allocated to participating restricted stock	(301		)	(254		)	(256		)
Net income available to common shareholders	$	91,127		$	88,329		$	90,590
Diluted net income per common share:
Net income	$	91,428		$	88,583		$	90,846
Income reallocated to participating restricted stock	(301		)	(254		)	(256		)
Net income available to common shareholders	$	91,127		$	88,329		$	90,590
Basic net income per common share:
Distributed earnings	$	1.105		$	1.045		$	0.97
Undistributed earnings	1.165			1.155			1.30
Basic net income per common share	$	2.270		$	2.200		$	2.27
Diluted net income per common share:
Distributed earnings	$	1.105		$	1.045		$	0.97
Undistributed earnings	1.165			1.155			1.29
Diluted net income per common share	$	2.270		$	2.200		$	2.26

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,
	2014	2013	2012
Restricted stock awards	60,455	51,489	45,178
Performance shares (a)	96,208	115,044	57,625

_____________________


(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	)

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EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

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



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

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

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

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

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

(a) These items are included in the computation of net periodic benefit cost. See Note M, Employee Benefits, for additional information.

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EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

I. Long-Term Debt and Financing Obligations

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



	December 31,
	2014			2013
	(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)	398,021			397,976
7.50% Senior Notes, net of discount, due 2038 (7.67% effective interest rate)	148,818			148,800
3.30% Senior Notes, net of discount, due 2022 (3.43% effective interest rate)	149,737			149,709
5.00% Senior Notes, net of discount, due 2044 (5.10% effective interest rate)	149,468			—
Total Senior Notes	846,044			696,485
RGRT Senior Notes (3):
3.67% Senior Notes, Series A, due 2015 (3.87% effective interest rate)	15,000			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	110,000			110,000
Total long-term debt	1,149,179			999,620
Financing Obligations:
Revolving Credit Facility ($14,532 due in 2015) (4)	14,532			14,352
Total long-term debt and financing obligations	1,163,711			1,013,972
Current Portion (amount due within one year):
Current maturities of long term debt	(15,000		)	—
Short-term borrowings under the revolving credit facility	(14,532		)	(14,352		)
	$	1,134,179		$	999,620

_____________________


(1)	Pollution Control Bonds ("PCBs")

The Company has four series of tax exempt unsecured PCBs in aggregate principal amount of $193.1 million. The 1.875% 2012 Series A (El Paso Electric Company Four Corners Project) Pollution Control Refunding Revenue Bonds with an aggregate principal amount of $33.3 million are subject to mandatory tender for purchase in September 2017.


(2)	Senior Notes

The Senior Notes are unsecured obligations of the Company. They were issued pursuant to bond covenants that provide limitations on the Company’s ability to enter into certain transactions. The 6.00% Senior Notes have an aggregate principal amount of $400.0 million and were issued in May 2005. The proceeds, net of a $2.3 million discount, were used to fund the retirement of the Company's first mortgage bonds. The Company amortizes the loss associated with a cash flow hedge recorded in accumulated other comprehensive income to earnings as interest expense over the life of the 6.00% Senior Notes. See Note O, "Financial Instruments and Investments - Treasury Rate Locks". This amortization is included in the effective interest rate of the 6.00% Senior Notes.

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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") of which $15.0 million will mature in August 2015. The Company will either repay or refinance this $15.0 million of Notes upon maturity. The Company guarantees the payment of principal and interest on the Notes. In the Company’s financial statements, the assets and liabilities of 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 2014.

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 2014. As of December 31, 2014, the total amount borrowed by RGRT was $14.5 million for nuclear fuel under the RCF. As of December 31, 2014, no borrowings were outstanding under this facility for working capital and general corporate purposes. The weighted average interest rate on the RCF was 1.3% as of December 31, 2014.

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EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

As of December 31, 2014, the scheduled maturities for the next five years of long-term debt are as follows (in thousands):




2015	$	15,000
2016	—
2017	83,300
2018	—
2019	—

The $14.5 million outstanding on the RCF for nuclear fuel financing purposes is anticipated to be paid in 2015.

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, 2014 and 2013 are presented below (in thousands):



	December 31,
	2014			2013
Deferred tax assets:
Benefit of tax loss carryforwards	$	—		$	17,709
Alternative minimum tax credit carryforward	17,701			21,638
Pensions and benefits	64,407			54,652
Asset retirement obligation	25,725			23,727
Other	15,768			14,485
Total gross deferred tax assets	123,601			132,211
Deferred tax liabilities:
Plant, principally due to depreciation and basis differences	(536,264		)	(511,847		)
Decommissioning	(40,373		)	(35,489		)
Deferred fuel	(3,531		)	(2,171		)
Other	(3,630		)	(5,664		)
Total gross deferred tax liabilities	(583,798		)	(555,171		)
Net accumulated deferred income taxes	$	(460,197	)	$	(422,960	)

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 2014, 2013 and 2012 as follows (in thousands):



	Years Ended December 31,
	2014			2013			2012
Income tax expense:
Federal:
Current	$	(1,250	)	$	(2,877	)	$	1,487
Deferred	38,810			45,024			43,187
Total federal income tax	37,560			42,147			44,674
State:
Current	3,209			1,854			1,931
Deferred	641			(414		)	697
Total state income tax	3,850			1,440			2,628
Generation (amortization) of accumulated investment tax credits	(322		)	68			(323		)
Total income tax expense	$	41,088		$	43,655		$	46,979

As of December 31, 2014, the Company had $17.7 million of AMT credit carryforwards that have an unlimited life. As of December 31, 2014, the Company has utilized all of the federal and state tax loss carryfowards.

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,
	2014			2013			2012
Federal income tax expense computed on income at statutory rate	$	46,381		$	46,283		$	48,239
Difference due to:
State taxes, net of federal benefit	1,902			936			1,708
AEFUDC	(3,757		)	(2,149		)	(1,845		)
Permanent tax differences	(2,921		)	(1,153		)	(604		)
Other	(517		)	(262		)	(519		)
Total income tax expense	$	41,088		$	43,655		$	46,979
Effective income tax rate	31.0		%	33.0		%	34.1		%

The Company files income tax returns in the United States ("U.S.") federal jurisdiction and in the states of Texas, New Mexico and Arizona. The Company is no longer subject to tax examination by the taxing authorities in the federal and New Mexico jurisdictions for years prior to 2010. The Company is currently under audit in Texas for tax years 2007 through 2011 and in Arizona for tax years 2009 through 2012. The Company reached a settlement agreement with the Arizona Department of Revenue (“ADOR”) in March 2014 in their audit of income tax returns for the years 1998 through 2007 which did not have a material effect on income tax expense. Additionally, the Company reached a settlement with ADOR in September of 2014 in their audit of the income tax return for 2008 which did not have a material effect on income tax expense.

On December 19, 2014, the President signed the Tax Increase Prevention Act of 2014. This act included the extension of bonus depreciation which impacted the Company. The Company recorded the impact of the law change in December 2014, which resulted in an $0.8 million increase in income tax expense due to a decrease in the domestic production activities deduction which is limited by taxable income.

FASB guidance prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. In January 2010, the Company filed for a change of accounting method with the IRS related to the way in which units of property are determined for purposes of determining capitalized tax assets. The change was included in the 2009 federal income tax return, with additional amounts included in the 2010 to 2013 federal income tax returns. The Company recorded an unrecognized tax position of $1.6 million in 2012, related to the change in accounting method in 2009 through 2012. In 2013, a $4.5 million decrease was made to the reserve related to the change in accounting method. The decrease was primarily the result of the completion of IRS audits for tax years 2009 to 2012. In September

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EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

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 adjustment to the deduction taken in previous tax returns by the Company was required. As a result of the IRA, 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 $2.1 million, $0.5 million and $1.4 million in 2014, 2013 and 2012, 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) to its unrecognized tax position 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, 2014, 2013 and 2012 amount of unrecognized tax benefits is as follows (in thousands):



	2014			2013			2012
Balance at January 1	$	7,200		$	9,800		$	9,500
Additions for tax positions related to the current year	300			600			1,600
Reductions for tax positions related to the current year	—			—			(900		)
Additions for tax positions of prior years	2,200			1,700			1,400
Reductions for tax positions of prior years	(4,500		)	(4,900		)	(1,800		)
Balance at December 31	$	5,200		$	7,200		$	9,800

If recognized, $3.0 million of the unrecognized tax position at December 31, 2014, would affect the effective tax rate. The Company recognized income tax expense for an unrecognized tax position of $0.5 million for the year ended December 31, 2014.

The Company recognizes in tax expense interest and penalties related to tax benefits that have not been recognized. During the year ended December 31, 2012, the Company recognized a benefit of $0.3 million in interest. For the years ended December 31, 2014 and 2013, the Company recognized interest expense of $0.1 million and $0.2 million, respectively. The Company had approximately $0.5 million and $0.4 million accrued for the payment of interest and penalties at December 31, 2014 and 2013, respectively.

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EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

K. Commitments, Contingencies and Uncertainties

Power Purchase and Sale Contracts

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



					Commercial
					Operation
Type of Contract	Counterparty	Quantity		Term	Date
Power Purchase and Sale Agreement	Freeport	25	MW	December 2008 through December 2015	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	Sun Edison 1	10	MW	June 2012 through June 2037	June 2012
Power Purchase Agreement	Sun Edison 2	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	PSEG El Paso Solar Energy Center	10	MW	December 2014 through November 2044	December 2014

The Company has a firm Power Purchase and Sale Agreement with Freeport-McMoran Copper and Gold Energy Services LLC ("Freeport") which provides for Freeport to deliver energy to the Company from its ownership interest in the Luna Energy Facility (a natural gas-fired combined cycle generation facility located in Luna County, New Mexico) and for the Company to deliver a like amount of energy at Greenlee, Arizona. The Company may purchase the quantities noted in the table above at a specified price at times when energy is not exchanged under the Power Purchase and Sale Agreement. Upon mutual agreement, the contract allows the parties to increase the amount of energy that is purchased and sold under the Power Purchase and Sale Agreement. The parties have agreed to increase the amount up to 125 MW through December 2015. The contract was approved by the FERC and continues through December 31, 2021. On December 30, 2014, the FERC issued an order authorizing the disposition, i.e. sale, of Freeport's interest in the Luna facility to Samchully Power & Utilities 1, LLC. Freeport will retain the ability to purchase up to the full amount of its previous ownership share of the Luna facility of approximately 190 MW, thereby continuing to fulfill its obligations pursuant to the Power Purchase and Sale Agreement.

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. The Company 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. 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, SunEdison 1 and SunEdison 2 which began commercial operation on June 25, 2012 and May 2, 2012, respectively. The Company entered into these contracts to help meet its renewable portfolio requirements. The Company 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 on May 23, 2014. The Company has a 30-year purchase power agreement with PSEG El Paso Solar Energy Center ("PSEG") to purchase the total output of approximately 10 MW from a solar photovoltaic plant that PSEG owns and operates on land subleased from the Company in proximity to its Newman Power Station. This solar photovoltaic plant began commercial operation on December 30, 2014.

The Company entered into an agreement in 2009 to purchase capacity and unit contingent energy during 2010 from Shell Energy North America ("Shell"). Under the agreement, the Company provided natural gas to Pyramid Unit No. 4 where Shell had the right to convert natural gas to electric energy. The Company entered into a contract with Shell on May 17, 2010 to extend the term of the capacity and unit contingent energy purchase from January 1, 2011 through September 30, 2014.

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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 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. On October 23, 2014, the D.C. Circuit lifted its stay of CSAPR, and while we are unable to determine the full impact of the reinstatement of CSAPR until the D.C. Circuit and the EPA take further action, the Company believes it is currently positioned to comply with CSAPR.

National Ambient Air Quality Standards. Under the CAA, the EPA sets National Ambient Air Quality Standards ("NAAQS") for six criteria pollutants considered harmful to public health and the environment, including PM, NOx, carbon monoxide ("CO"), ozone and SO2. NAAQS must be reviewed by the EPA at five-year intervals. In 2010, the EPA tightened the NAAQS for both NOx and SO2. The EPA is considering a 1-hour secondary NAAQS for NOx and SO2. In January 2013, the EPA tightened the NAAQS for fine PM. On November 26, 2014, the EPA announced a proposal to tighten the 2008 primary and secondary ground-level ozone NAAQS. 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. EPA proposes to tighten the current 8-hour primary (health-based) standard of 75 parts per billion ("ppb") to a level within its preferred range of 65 to 70 ppb, while also taking comment on a potential standard as low as 60 ppb and on retaining the current standard. The EPA intends to issue a final rule by October 2015.The Company continues to evaluate what impact these final and proposed NAAQS could have on its operations. If the Company is required to install additional equipment to control emissions at its facilities, the revised NAAQS could have a material impact on its operations and financial results.

Utility MACT. The operation of coal-fired power plants, such as 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 "Utility MACT") for oil-and coal-fired power plants, which requires significant reductions in emissions of mercury and other air toxics. Several judicial and other challenges have been made to this rule, with a U.S. Supreme Court decision expected this year. These challenges notwithstanding, companies impacted by the new standards will generally have up to three years to comply. Information from the Four Corners plant operator, APS, indicates that APS currently believes Units 4 and 5 will require no additional modifications to achieve compliance with the Utility MACT standards.

Other Laws and Regulations and Risks. As stated above, the Company 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 will avoid the significant cost required to install 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.

Climate Change. The U.S. federal government has either considered, proposed and/or finalized legislation or regulations limiting GHG emissions, including carbon dioxide. In particular, the U.S. Congress 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,

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NOTES TO FINANCIAL STATEMENTS

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 January 2014, the EPA published a proposal to establish new source performance standards limiting carbon dioxide emissions from new electric generating units, and in June 2014, a proposal to create carbon dioxide standards for existing and modified/reconstructed power plants. The Company participated in the associated proposed rulemaking comment periods. On January 7, 2015, EPA announced it plans to issue final rules for new, existing and modified/reconstructed power plants by this summer. Given the very significant remaining uncertainties regarding these EPA rules, the Company believes it is impossible to meaningfully quantify the costs of these potential requirements at present.

In addition, almost half the U.S. states, either individually and/or through multi-state regional initiatives, have begun to consider how to address GHG emissions and have developed, or are actively considering the development of emission inventories or regional GHG cap and trade programs. While a significant portion of the Company's generation assets are nuclear or gas-fired, and as a result, the Company believes that its greenhouse gas emissions are low relative to electric power companies who rely more on coal-fired generation, current and future legislation and regulation of GHGs or any future related litigation could impose significant costs and/or operating restrictions on the Company, reduced demand for the power the Company generates and/or require the Company to purchase rights to emit GHGs, any of which could be material to the Company's business, financial condition, reputation or results of operations.

Climate change also has potential physical effects that could be relevant to the Company's business. In particular, some studies suggest that climate change could affect the Company's service area by causing higher temperatures, less winter precipitation and less spring runoff, as well as by causing more extreme weather events. Such developments could change the demand for power in the region and could also impact the price or ready availability of water supplies or affect maintenance needs and the reliability of Company equipment. The Company believes that material effects on the Company's business or results of operations may result from the physical consequences of climate change, the regulatory approach to climate change ultimately selected and implemented by governmental authorities, or both. Given the very significant remaining uncertainties regarding whether and how these issues will be regulated, as well as the timing and severity of any physical effects of climate change, the Company believes it is impossible to meaningfully quantify the costs of these potential impacts at present.

Environmental Litigation and Investigations. Since 2009, the EPA and certain environmental organizations have been scrutinizing, and in some cases, have filed lawsuits, relating to certain air emissions and air permitting matters related to Four Corners. In particular, since July 2011, the U.S. Department of Justice (the "DOJ"), on behalf of the EPA, and APS have been engaged in substantive settlement negotiations in an effort to resolve certain of the pending matters. The allegations being addressed through settlement negotiations are that APS failed to obtain the necessary permits and install the controls necessary under the CAA to reduce SO2, NOx, and PM, and that defendants failed to obtain an operating permit under Title V of the CAA that reflects applicable requirements imposed by law. In 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. Settlement discussions are on-going and the Company is unable to predict with certainty the final outcome of these settlement negotiations. The Company has accrued a total of $0.6 million as its estimated share of the loss contingency related to this matter.

Earthjustice filed a lawsuit in the United States District Court for New Mexico on October 4, 2011 for alleged violations of the Prevention of Significant Deterioration ("PSD") provisions of the CAA related to Four Corners. On January 6, 2012, Earthjustice filed a First Amended Complaint adding claims for violations of the CAA's New Source Performance Standards ("NSPS") program. Among other things, the plaintiffs seek to have the court enjoin operations at Four Corners until APS applies for and obtains any required PSD permits and complies with the referenced NSPS program. The plaintiffs further request the court to order the payment of civil penalties, including a beneficial mitigation project. On April 2, 2012, APS and the other Four Corners participants filed motions to dismiss with the court. The case is being held in abeyance while the parties seek to negotiate a settlement. On March 30, 2013, upon joint motion of the parties, the court issued an order deeming the motions to dismiss withdrawn without prejudice during pendency of the stay. At such time as the stay is lifted, APS, the Company and the other Four Corners participants may reinstate the motions to dismiss. Settlement discussions are ongoing. The Company is unable to predict the outcome of this litigation.

New Mexico Tax Matter Related to Coal Supplied to Four Corners

On May 23, 2013, the New Mexico Taxation and Revenue Department issued a notice of assessment for coal severance surtax, penalty, and interest totaling approximately $30 million related to coal supplied under the coal supply agreement for Four Corners (the "Assessment"). The Company's share of the assessment is approximately $1.5 million. On behalf of the Four Corners

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NOTES TO FINANCIAL STATEMENTS

participants, the coal supplier made a partial payment of the Assessment and immediately filed a refund claim with respect to that partial payment in August 2013. The New Mexico Taxation and Revenue Department denied the refund claim. On December 19, 2013, the coal supplier and APS, on its own behalf and as operating agent for Four Corners, filed complaints with the New Mexico District Court contesting both the validity of the Assessment and the refund claim denial. APS believes the Assessment and the refund claim denial are without merit. The Company cannot predict the timing, results, or potential impacts of the outcome of this litigation.

Lease Agreements

The Company leases land in El Paso adjacent to the Newman Power Station under a lease which expires in June 2033 with a renewal option of 25 years. In addition, the Company leases certain warehouse facilities in El Paso under a lease which expires in December 2015. The Company also has several other leases for office, parking facilities and equipment which expire within the next three 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 $1.8 million, $1.2 million, and $1.3 million for 2014, 2013 and 2012, respectively. As of December 31, 2014, the Company’s minimum future rental payments for the next five years are as follows (in thousands):



2015	$	1,386
2016	838
2017	623
2018	512
2019	516

L. Litigation

See 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 are 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 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,
	2014						2013
	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	$	317,815		$	25,898		$	320,846		$	27,241
Service cost	8,284			303			9,137			190
Interest cost	14,001			1,041			12,742			872
Amendments (a)	(33,700		)	(500		)	—			—
Actuarial (gain) loss	50,741			3,508			(15,373		)	(533		)
Benefits paid	(16,008		)	(1,853		)	(9,537		)	(1,872		)
Benefit obligation at end of year	341,133			28,397			317,815			25,898
Change in plan assets:
Fair value of plan assets at end of prior year	257,831			—			220,568			—
Actual return on plan assets	22,116			—			31,800			—
Employer contribution	9,000			1,853			15,000			1,872
Benefits paid	(16,008		)	(1,853		)	(9,537		)	(1,872		)
Fair value of plan assets at end of year	272,939			—			257,831			—
Funded status at end of year	$	(68,194	)	$	(28,397	)	$	(59,984	)	$	(25,898	)

_____________________

(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,
	2014						2013
	Retirement Income Plan			Non-Qualified Retirement Plans			Retirement Income Plan			Non-Qualified Retirement Plans
Current liabilities	$	—		$	(2,319	)	$	—		$	(1,870	)
Noncurrent liabilities	(68,194		)	(26,078		)	(59,984		)	(24,028		)
Total	$	(68,194	)	$	(28,397	)	$	(59,984	)	$	(25,898	)

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



	December 31,
	2014						2013
	Retirement Income Plan			Non-Qualified Retirement Plans			Retirement Income Plan			Non-Qualified Retirement Plans
Projected benefit obligation	$	(341,133	)	$	(28,397	)	$	(317,815	)	$	(25,898	)
Accumulated benefit obligation	(312,762		)	(27,603		)	(275,555		)	(25,077		)
Fair value of plan assets	272,939			—			257,831			—

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,
	2014						2013
	Retirement Income Plan			Non-Qualified Retirement Plans			Retirement Income Plan		Non-Qualified Retirement Plans
Net loss	$	124,407		$	11,341		$	85,261	$	8,508
Prior service cost (benefit)	(30,811		)	(264		)	—		219
Total	$	93,596		$	11,077		$	85,261	$	8,727

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



	December 31,
	2014						2013
			Non-Qualified						Non-Qualified
	Retirement Income Plan		Supplemental Retirement Plan		Excess Benefit Plan		Retirement Income Plan		Supplemental Retirement Plan		Excess Benefit Plan
Discount rate	4.0	%	3.4	%	4.1	%	4.9	%	3.9	%	4.9	%
Rate of compensation increase	4.5	%	N/A		4.5	%	4.75	%	N/A		4.75	%

The Company reassesses various actuarial assumptions at least on an annual basis. The discount rate is reviewed at each measurement date. The discount rate used to measure obligations is based on a spot rate yield curve that matches projected future payments with the appropriate interest rate applicable to the timing of the projected future benefit payments. A 1% increase in the discount rate would decrease the December 31, 2014 retirement plans' projected benefit obligation by 11.7%. A 1% decrease in the discount rate would increase the December 31, 2014 retirement plans' projected benefit obligation by 14.6%.

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



	Years Ended December 31,
	2014						2013					2012
	Retirement Income Plan			Non-Qualified Retirement Plans			Retirement Income Plan			Non-Qualified Retirement Plans		Retirement Income Plan			Non-Qualified Retirement Plans
Service cost	$	8,284		$	303		$	9,137		$	190	$	8,530		$	299
Interest cost	14,001			1,041			12,742			872		12,594			963
Expected return on plan assets	(18,699		)	—			(17,108		)	—		(14,443		)	—
Amortization of:
Net loss	8,178			675			10,437			661		10,729			627
Prior service cost (benefit)	(2,889		)	(17		)	3			94		21			94
Net periodic benefit cost	$	8,875		$	2,002		$	15,211		$	1,817	$	17,431		$	1,983

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,
	2014						2013						2012
	Retirement Income Plan			Non-Qualified Retirement Plans			Retirement Income Plan			Non-Qualified Retirement Plans			Retirement Income Plan			Non-Qualified Retirement Plans
Net (gain) loss	$	47,324		$	3,508		$	(30,065	)	$	(533	)	$	6,672		$	1,337
Prior service benefit	(33,700		)	(500		)	—			—			—			—
Amortization of:
Net loss	(8,178		)	(675		)	(10,437		)	(661		)	(10,729		)	(627		)
Prior service (cost) benefit	2,889			17			(3		)	(94		)	(21		)	(94		)
Total recognized in other comprehensive income	$	8,335		$	2,350		$	(40,505	)	$	(1,288	)	$	(4,078	)	$	616

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



	Years Ended December 31,
	2014				2013					2012
	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	$	17,210	$	4,352	$	(25,294	)	$	529	$	13,353	$	2,599

The following are amounts in accumulated other comprehensive income that are expected to be recognized as components of net periodic benefit cost during 2015 (in thousands):



	Retirement Income Plan			Non-Qualified Retirement Plans
Net loss	$	10,220		$	850
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:



	2014 (a)						2013						2012
			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	4.9	%	3.9	%	4.9	%	4.0	%	3.1	%	4.0	%	4.3	%	3.6	%	4.1	%
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	4.75	%	N/A		4.75	%	4.75	%	N/A		4.75	%	5.0	%	N/A		5.0	%

_____________________


(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, 2014, 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, 2014
Equity securities	55	%
Fixed income	40	%
Alternative investments	5	%
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. The Retirement Plan fund also invests in a real estate limited partnership. The expected rate of returns for the funds are assessed annually and are based on long-term relationships among major asset classes and the level of incremental returns that can be earned by the successful implementation of different active investment management strategies. Equity returns are based on estimates of long-term inflation rate, real rate of return, 10-year Treasury bond premium over cash and equity risk premium. Fixed income returns are based on maturity, long-term inflation, real rate of return and credit spreads.

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


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

•

Level 2 – Inputs other than quoted market prices included in Level 1 that are observable for the asset or liability either directly or indirectly. The fair value of the Guaranteed Investment Contract was based on market interest rates of investments with similar terms and risk characteristics. The Common Collective Trusts are valued using the net asset value ("NAV") provided by the administrator of the fund. The NAV price is quoted on a restrictive market although the underlying investments are traded on active markets.


•	Level 3 – Unobservable inputs using data that is not corroborated by market data. The fair value of the real estate limited partnership is reported at the NAV of the investment.

Table of Contents

EL PASO ELECTRIC COMPANY

NOTES TO FINANCIAL STATEMENTS

The fair value of the Company’s Retirement Plan assets at December 31, 2014 and 2013, and the level within the three levels of the fair value hierarchy defined by FASB guidance on fair value measurements are presented in the table below (in thousands):



Description of Securities	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 Trusts (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



Description of Securities	Fair Value as of December 31, 2013		Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Cash and Cash Equivalents	$	940	$	940	$	—	$	—
Guaranteed Investment Contract	1,126		—		1,126		—
Common Collective Trust (a)
Equity funds	142,960		—		142,960		—
Fixed income funds	103,948		—		103,948		—
Total Common Collective Trusts	246,908		—		246,908		—
Limited Partnership Interest in Real Estate (b)	8,857		—		—		8,857
Total Plan Investments	$	257,831	$	940	$	248,034	$	8,857

_____________________


(a)	The Common Collective Trusts are invested in equity or fixed income securities, or a combination thereof. The investment objective of each trust is to produce returns in excess of, or commensurate with, its predefined index.

(b)

This investment is a commercial real estate partnership that purchases land, develops limited infrastructure, and sells it for commercial development. The Company is restricted from selling its partnership interest during the life of the partnership which is generally 5-7 years. Return on investment is realized as land is sold. The fair value of the limited partnership interest in real estate is based on the NAV of the partnership which reflects the appraised value of the land.

The table below reflects the changes in the fair value of investments in real estate during the period (in thousands):



	Fair Value of Investments in Real Estate
Balances at December 31, 2012	$	8,559
Unrealized gain in fair value	298
Balances at December 31, 2013	8,857
Sale of land	(357		)
Unrealized gain in fair value	248
Balances at December 31, 2014	$	8,748

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, 2014 and 2013. 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, 2014 and 2013.

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 $11.3 million to its retirement plans in 2015.

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
2015	$	15,776	$	2,319
2016	17,153		2,248
2017	17,778		2,171
2018	20,019		2,196
2019	19,500		2,135
2020-2024	103,703		10,720

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 2014, 2013 and 2012 were $3.0 million, $1.9 million, and $1.8 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 limits the Company's premium contribution. The amendment became effective October 3, 2013 and resulted in a remeasurement of the plan.



	2014		2013 (a)		2012
Discount rate at beginning of year	4.9	%	4.1	%	4.3	%
Expected long-term return on plan assets	5.2	%	5.2	%	5.2	%
Health care cost trend rates:
Initial	7.5	%	7.75	%	8.0	%
Ultimate	4.5	%	4.5	%	4.5	%
Year ultimate reached	2026		2026		2026



	Fair Value of Investments in Real Estate
Balance at December 31, 2012	$	1,605
Unrealized gain in fair value	56
Balance at December 31, 2013	1,661
Sale of land	(67		)
Unrealized gain in fair value	46
Balance at December 31, 2014	$	1,640



2015	$	3,163
2016	3,528
2017	3,906
2018	4,303
2019	4,570
2020-2024	27,362



	December 31, 2014
	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	$	—	$	—		$	2,383	$	(57	)	$	2,383	$	(57	)
U.S. Government Bonds	1,552		(2		)	20,060		(573		)	21,612		(575		)
Municipal Obligations	6,433		(65		)	8,570		(410		)	15,003		(475		)
Corporate Obligations	2,455		(24		)	2,461		(111		)	4,916		(135		)
Total Debt Securities	10,440		(91		)	33,474		(1,151		)	43,914		(1,242		)
Common Stock	1,475		(229		)	—		—			1,475		(229		)
Common Collective Trust-Equity Funds	22,736		(821		)	—		—			22,736		(821		)
Total Temporarily Impaired Securities	$	34,651	$	(1,141	)	$	33,474	$	(1,151	)	$	68,125	$	(2,292	)



	Total		2015		2016 through 2019		2020 through 2024		2025 and Beyond
Municipal Debt Obligations	$	26,645	$	1,011	$	11,318	$	12,967	$	1,349
Corporate Debt Obligations	18,678		720		5,163		6,517		6,278
U.S. Government Bonds	41,628		3,050		17,520		12,062		8,996


•	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.



	2014 Quarters								2013 Quarters
	4th		3rd		2nd		1st		4th		3rd		2nd		1st
					(In thousands except for share data)
Operating revenues (1)	$	196,563	$	283,645	$	251,801	$	185,516	$	190,297	$	282,661	$	240,114	$	177,290
Operating income	8,871		81,496		51,131		9,665		6,050		85,896		54,344		19,345
Net income	4,241		52,476		30,096		4,615		1,191		50,565		29,193		7,634
Basic earnings per share:
Net income	0.10		1.30		0.75		0.11		0.03		1.26		0.73		0.19
Diluted earnings per share:
Net income	0.10		1.30		0.75		0.11		0.03		1.26		0.72		0.19
Dividends declared per share of common stock	0.280		0.280		0.280		0.265		0.265		0.265		0.265		0.25


(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



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	—	$	—	1,549,014
Equity compensation plans
not approved by security holders	—	—		—
Total	—	$	—	1,549,014


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



		Page
1.	Financial Statements:

	See Index to Financial Statements	43

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		–	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)
4.01-03		–	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)
	4.02	–	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)
	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)



Exhibit Number			Title
	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)
	10.02	–	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)
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)



Exhibit Number			Title
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)
	10.05	–	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)
	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)



Exhibit Number			Title
	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)
	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)



Exhibit Number			Title
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)
10.28		–	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		–	Reserved
	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)
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.
	10.43	–	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



Exhibit Number			Title
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)
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 112 of this report)
Exhibit 24 –		Power of Attorney:
*24.01		–	Power of Attorney (set forth on page 110 of the Original Form 10-K)
*24.02		–	Certified copy of resolution authorizing signatures pursuant to Power of Attorney
Exhibit 31 and 32 –		Certifications:
*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



Exhibit Number		Title
*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/ THOMAS V. SHOCKLEY III
	Thomas V. Shockley III
	Chief Executive Officer (Principal Executive Officer)



Signature	Title	Date

/s/ THOMAS V. SHOCKLEY III	Chief Executive Officer (Principal Executive Officer and Director)	February 27, 2015
(Thomas V. Shockley III)

/s/ NATHAN T. HIRSCHI	Senior Vice President and Chief Financial Officer (Principal Financial Officer)	February 27, 2015
(Nathan T. Hirschi)

/s/ RUSSELL G. GIBSON	Vice President and Controller	February 27, 2015
(Russell G. Gibson)

/s/ CATHERINE A. ALLEN	Director	February 27, 2015
(Catherine A. Allen)

/s/ JOHN ROBERT BROWN	Director	February 27, 2015
(John Robert Brown)

/s/ JAMES W. CICCONI	Director	February 27, 2015
(James W. Cicconi)

/s/ EDWARD ESCUDERO	Director	February 27, 2015
(Edward Escudero)

/s/ JAMES W. HARRIS	Director	February 27, 2015
(James W. Harris)

/s/ PATRICIA Z. HOLLAND-BRANCH	Director	February 27, 2015
(Patricia Z. Holland-Branch)

/s/ WOODLEY L. HUNT	Director	February 27, 2015
(Woodley L. Hunt)

/s/ ERIC B. SIEGEL	Director	February 27, 2015
(Eric B. Siegel)

/s/ STEPHEN N. WERTHEIMER	Director	February 27, 2015
(Stephen N. Wertheimer)

/s/ CHARLES A. YAMARONE	Director	February 27, 2015
(Charles A. Yamarone)