2014 10-K

10-K 1 a201410-k.htm FORM 10-K 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.

Table of Contents

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



	( i)

Table of Contents

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



	( ii)

Table of Contents

FORWARD-LOOKING STATEMENTS

Certain matters discussed in this Annual Report on Form 10-K other than statements of historical information are "forward-looking statements." The Private Securities Litigation Reform Act of 1995 has established that these statements qualify for safe harbors from liability. Forward-looking statements may include words like we "believe", "anticipate", "target", "expect", "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,



	( iii)

Table of Contents


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


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


•	political, legislative, judicial and regulatory developments,


•	the impact of lawsuits filed against us,


•	the impact of changes in interest rates,


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


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


•	the impact of changing cost escalation and other assumptions on our nuclear decommissioning liability for Palo Verde, 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.



	( iv)

Table of Contents

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.

Table of Contents

Palo Verde Station

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

•

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.

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,

Table of Contents

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.

Table of Contents

•

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.

Table of Contents

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



Line	Length (miles)	Voltage (kV)	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.

Table of Contents

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

__________________________


(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.

Table of Contents

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.

Table of Contents

Coal

APS, as operating agent for Four Corners, purchases Four Corners' coal requirements from a supplier with a long-term lease of coal reserves owned by the Navajo Nation.

On December 30, 2013, APS and Southern California Edison ("SCE") closed their previously announced transaction whereby APS agreed to purchase SCE's 48% interest in Units 4 and 5 of Four Corners. Concurrently with the closing of this transaction, the ownership of BHP Navajo Coal Company, the coal supplier and operator of the mine that serves Four Corners, was transferred to Navajo Transitional Energy Company, LLC ("NTEC"), a company formed by the Navajo Nation to own the mine and develop other energy projects.

Purchased Power

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

The Company has a firm 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.

Table of Contents

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.

Table of Contents

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.

Table of Contents

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.

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

Table of Contents

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.

Table of Contents

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.

Table of Contents

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.

Table of Contents

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

Table of Contents

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

Table of Contents

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

Table of Contents

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

Table of Contents

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.

Table of Contents


Item 1B.	Unresolved Staff Comments

None.


Item 2.	Properties

The principal properties of the Company are described in Item 1, "Business," and such descriptions are incorporated herein by reference. Transmission lines are located either on 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.

Table of Contents

PART II


Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

The Company’s common stock trades on the New York Stock Exchange ("NYSE") under the symbol "EE". The intraday high, intraday low and close sales prices for the Company’s common stock, as reported in the consolidated reporting system of the NYSE, and quarterly dividends per share paid by the Company for the periods indicated below were as follows:



	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.

Table of Contents

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.

Table of Contents


Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations

As you read this Management’s Discussion and Analysis, please refer to our Financial Statements and the accompanying notes, which contain our operating results.

Summary of Critical Accounting Policies and Estimates

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

Regulatory Accounting

We apply accounting standards that recognize the economic effects of rate regulation in our Texas, New Mexico and FERC jurisdictions. As a result, we record certain costs or obligations as either assets or liabilities on our balance sheet and amortize them in subsequent periods as they are reflected in regulated rates. The deferral of costs as regulatory assets is appropriate only when the future recovery of such costs is probable. In assessing probability, we consider such factors as specific regulatory orders, regulatory precedent and the current regulatory environment. As of December 31, 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

Table of Contents

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

Table of Contents

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.

Table of Contents


(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.

Table of Contents

Historical Results of Operations

The following discussion includes detailed descriptions of factors affecting individual line items in the results of operations. The amounts presented below are presented on a pre-tax basis.

Operating revenues

We 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

Table of Contents

Customer growth is a key driver in the growth of retail sales. The average number of retail customers grew 1.3% in 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.

Table of Contents

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.

Table of Contents

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.

Table of Contents



						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.

Table of Contents

Energy expenses

Our sources of energy include electricity generated from our nuclear, natural gas and coal generating plants and purchased power. Palo Verde represents approximately 34% of our available net generating capacity and approximately 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